Edgar Filing: ENERSIS S.A.

FORM 20-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F


¨		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2012

OR

¨		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

¨		SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report

For the transition period from to

Commission file number: 001-12440

ENERSIS S.A.

(Exact name of Registrant as specified in its charter)

ENERSIS S.A.

(Translation of Registrant’s name into English)

CHILE

(Jurisdiction of incorporation or organization)

SANTA ROSA 76, SANTIAGO, CHILE

(Address of principal executive offices)

Nicolás Billikopf, phone: (56-2) 2353-4639, fax: (56-2) 2378-4789, nbe@enersis.cl, Santa Rosa 76, Piso 15, Santiago, Chile

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act:


		Title of Each Class				Name of Each Exchange on Which Registered
		American Depositary Shares representing Common Stock				New York Stock Exchange
		Common Stock, no par value *				New York Stock Exchange
		US$ 249,734,000 7.40% Notes due December 1, 2016				New York Stock Exchange
		US$ 858,000 6.60% Notes due December 1, 2026				New York Stock Exchange

*Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

US$ 350,000,000 7.375% Notes due January 15, 2014

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:


Shares of Common Stock:		32,651,166,465

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:

x Yes ¨ No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934:

¨ Yes x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days:

x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

¨ Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act:


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:


U.S. GAAP ¨		International Financial Reporting Standards as issued by the International Accounting Standards Board x		Other ¨

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow:

¨ Item 17 x Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):

¨ Yes x No

Enersis’ Simplified Organizational Structure (1)

As of December 31, 2012

LOGO

(1)	Only principal operating subsidiaries are presented here. The percentage listed for each of our subsidiaries represents Enersis’ economic interest in such subsidiary.

TABLE OF CONTENTS


		Page
GLOSSARY			4
INTRODUCTION			9
Financial Information			9
Technical Terms			10
Calculation of Economic Interest			10
Forward-Looking Statements			10
PART I			14
Item 1.	Identity of Directors, Senior Management and Advisers		14
Item 2.	Offer Statistics and Expected Timetable		14
Item 3.	Key Information		14
Item 4.	Information on the Company		28
Item 4A.	Unresolved Staff Comments		106
Item 5.	Operating and Financial Review and Prospects		106
Item 6.	Directors, Senior Management and Employees		137
Item 7.	Major Shareholders and Related Party Transactions		148
Item 8.	Financial Information		149
Item 9.	The Offer and Listing		150
Item 10.	Additional Information		154
Item 11.	Quantitative and Qualitative Disclosures about Market Risk		169
Item 12	Description of Securities Other Than Equity Securities		173
PART II			174
Item 13.	Defaults, Dividend Arrearages and Delinquencies		174
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds		174
Item 15.	Controls and Procedures		174
Item 16A.	Audit Committee Financial Expert		175
Item 16B.	Code of Ethics		175
Item 16C.	Principal Accountant Fees and Services		177
Item 16D.	Exemptions from the Listing Standards for Audit Committees		178
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers		178
Item 16F.	Change in Registrant’s Certifying Accountants		178
Item 16G.	Corporate Governance		178
Item 16H.	Mine Safety Disclosure		178
PART III			179
Item 17.	Financial Statements		179
Item 18.	Financial Statements		179
Item 19.	Exhibits		179

GLOSSARY


AFP	Administradora de Fondos de Pensiones	A legal entity that manages a Chilean pension fund.

Ampla	Ampla Energia e Serviços S.A.	A publicly held Brazilian distribution company operating in Rio de Janeiro, owned by Endesa Brasil, a subsidiary of Enersis.

ANEEL	Agência Nacional de Energia Elétrica	Brazilian governmental agency for electric energy.

Betania	Central Hidroeléctrica de Betania S.A. E.S.P.	A former Endesa Chile’s Colombian subsidiary that merged with Emgesa, another Endesa Chile subsidiary, in 2007.

Cachoeira Dourada	Centrais Elétricas Cachoeira Dourada S.A.	Brazilian generation company owned by Endesa Brasil, a subsidiary of Enersis.

CAM	Compañía Americana de Multiservicios Ltda.	A former Enersis’ subsidiary engaged in the electrical parts procurement business.

CAMMESA	Compañía Administradora del Mercado Mayorista Eléctrico S.A.	Argentine autonomous entity in charge of the operation of the Mercado Eléctrico Mayorista (Wholesale Electricity Market), or MEM. CAMMESA’s stockholders are generation, transmission and distribution companies, large users and the Secretariat of Energy.

CDEC	Centro de Despacho Económico de Carga	Autonomous entity in two Chilean electric systems in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand.

Celta	Compañía Eléctrica Tarapacá S.A.	Endesa Chile’s subsidiary that operates in the SING with thermal plants.

Cemsa	Endesa Cemsa S.A.	Energy trading company with operations in Argentina, and an associate of Endesa Chile.

Chilectra	Chilectra S.A.	Chilean electricity distribution company operating in the Santiago metropolitan area, a subsidiary of Enersis.

CIEN	Companhia de Interconexão Energética S.A.	Brazilian transmission company, wholly-owned by Endesa Brasil, a subsidiary of Enersis.

CNE	Comisión Nacional de Energía	Chilean National Energy Commission, governmental entity with responsibilities under the Chilean regulatory framework.

Codensa	Codensa S.A. E.S.P.	Colombian distribution company that operates mainly in Bogotá, and a subsidiary of Enersis.

Coelce	Companhia Energética do Ceará S.A.	A publicly held Brazilian distribution company operating in the state of Ceará. Coelce is controlled by Endesa Brasil, a subsidiary of Enersis.



COES	Comité de Operación Económica del Sistema	Peruvian entity in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand.

Cono Sur	Cono Sur Participaciones, S.L.U.	A newly formed subsidiary of Endesa Spain that holds its interests in certain electricity generation, transmission and holding companies and the shares of which will be contributed to Enersis in the In-Kind Contribution.

CREG	Comisión de Regulación de Energía y Gas	Colombian Commission for the Regulation of Energy and Gas.

CTM	Compañía de Transmisión del Mercosur S.A.	Endesa Brasil’s subsidiary transmission company with operations in Argentina.

DECSA	Distribuidora Eléctrica de Cundinamarca S.A.	Colombian distribution company and a subsidiary of Codensa.

Edegel	Edegel S.A.A.	A publicly held Peruvian generation company, subsidiary of Endesa Chile.

Edelnor	Empresa de Distribución Eléctrica de Lima Norte S.A.A.	A publicly held Peruvian distribution company with a concession area in the northern part of Lima, and a subsidiary of Enersis.

Edesur	Empresa Distribuidora Sur S.A.	Argentine distribution company with concession area in the south of the Buenos Aires greater metropolitan area, and a subsidiary of Enersis.

EEB	Empresa de Energía de Bogotá S.A.	Colombian stated-owned financial and energy holding company, with investments in the electricity generation, transmission, trading and distribution sectors; and in the natural gas transmission, distribution and trading sectors.

EEC	Empresa de Energía de Cundinamarca S.A.	Colombian electricity distribution company, subsidiary of DECSA.

El Chocón	Hidroeléctrica El Chocón S.A.	Endesa Chile’s Argentine generation subsidiary with two hydroelectric plants, El Chocón and Arroyito, both located in the Limay River, Argentina.

Elesur	Elesur S.A.	A former Chilean subsidiary of Enersis that absorbed Chilectra, and later changed its name to Chilectra.

Emgesa	Emgesa S.A. E.S.P.	Colombian generation company controlled by Endesa Chile.

Endesa Brasil	Endesa Brasil S.A.	Brazilian holding company, a subsidiary of Enersis.

Endesa Chile	Empresa Nacional de Electricidad S.A.	Our publicly held generation subsidiary with consolidated operations in four countries in South America.

Endesa Costanera	Endesa Costanera S.A.	A publicly held Argentine generation company controlled by Endesa Chile.



Endesa Eco	Endesa Eco S.A.	Chilean electricity company, owner of Central Eólica Canela S.A. and Ojos de Agua mini hydroelectric plant. Endesa Eco is an Endesa Chile subsidiary.

Endesa Fortaleza	Central Geradora Termelétrica Fortaleza S.A.	Operates a combined cycle generating plant, located in the state of Ceará. Endesa Fortaleza is wholly-owned by our subsidiary Endesa Brasil.

Endesa Latinoamérica	Endesa Latinoamérica, S.A.U.	A subsidiary of Endesa Spain and our direct controller, formerly known as Endesa Internacional, S.A.U.

Endesa Spain	Endesa, S.A.	A Spanish electricity generation and distribution company with a 60.6% beneficial interest in Enersis.

Enel	Enel S.p.A.	Italian power company, with a 92.1% controlling ownership of Endesa Spain.

Enersis	Enersis S.A.	Our company, a publicly held limited liability stock corporation incorporated under the laws of the Republic of Chile, with subsidiaries engaged primarily in the generation, transmission and distribution of electricity in Chile, Brazil, Colombia, Peru and Argentina. Registrant of this Report.

ENRE	Ente Nacional Regulador de la Electricidad	Argentine national regulatory authority for the energy sector.

ESM	Extraordinary Shareholders Meeting	Extraordinary Shareholders Meeting

Etevensa	Empresa de Generación Termoeléctrica Ventanilla S.A.	Peruvian generation company that merged with Edegel in 2006.

FONINVEMEM	Fondo para Inversiones Necesarias que permitan Incrementar la Oferta de Energía Eléctrica en el Mercado Eléctrico Mayorista	Argentine fund created to increase electricity supply in the MEM.

GasAtacama	GasAtacama S.A.	Company involved in gas transportation and electricity generation in northern Chile that is 50% owned by Endesa Chile.

Gener	AES Gener S.A.	Chilean generation company that competes with the Company in Chile, Argentina and Colombia.

GNL Quintero	GNL Quintero S.A.	Company created to develop, build, finance, own and operate a LNG regasification facility at Quintero Bay (Chile) in which LNG is unloaded, stored and regasified.

IDR	Issuer Default Rating	Reflects the relative vulnerability of an entity to default on its financial obligations.

IFRS	International Financial Reporting Standards	Accounting standards adopted by the Company on January 1, 2009.

IMV	Inmobiliaria Manso de Velasco Ltda.	Enersis’ wholly-owned subsidiary engaged in the real estate business.

LNG	Liquefied Natural Gas.	Liquefied natural gas.



MEM	Mercado Eléctrico Mayorista	Wholesale Electricity Market in Argentina, Colombia and Peru.

MME	Ministério de Minas e Energia	Brazilian Ministry of Mines and Energy.

NCRE	Non Conventional Renewable Energy	Energy sources which are continuously replenished by natural processes, such as wind, biomass, mini-hydro, geothermal, wave or tidal energy.

NIS	Sistema Interconectado Nacional	National interconnected electric system. There are such systems in Chile, Argentina, Brazil and Colombia.

ONS	Operador Nacional do Sistema Elétrico	Electric System National Operator. Brazilian non-profit private entity responsible for the planning and coordination of operations in interconnected systems.

Osinergmin	Organismo Supervisor de la Inversión en Energía y Minería	Energy and Mining Investment Supervisor Authority, the Peruvian regulatory electricity authority.

OSM	Ordinary Shareholders Meeting	Ordinary Shareholders Meeting

Pangue	Empresa Eléctrica Pangue S.A.	Chilean electricity company, owner of the Pangue power station. Pangue was an Endesa Chile subsidiary which was merged into San Isidro in the first half of 2012.

Pehuenche	Empresa Eléctrica Pehuenche S.A.	A publicly held Chilean electricity company, owner of three power stations in the Maule River basin. Pehuenche is an Endesa Chile subsidiary.

San Isidro	Compañía Eléctrica San Isidro S.A.	Chilean electricity company, owner of a thermal power station and of Pangue power station.

SEF	Superintendencia de Electricidad y Combustible	Chilean Superintendency of Electricity and Fuels, a Governmental entity in charge of supervising the Chilean electricity industry.

SEIN	Sistema Eléctrico Interconectado Nacional	Peruvian interconnected electric system.

SIC	Sistema Interconectado Central	Chilean central interconnected electric system covering all of Chile except the north and the extreme south.

SING	Sistema Interconectado del Norte Grande	Electric interconnected system operating in northern Chile.

SVS	Superintendencia de Valores y Seguros	Chilean authority in charge of supervising public companies, securities and the insurance business.

TESA	Transportadora de Energía S.A.	Endesa Brasil’s transmission company subsidiary with operations in Argentina.

UF	Unidad de Fomento	Chilean inflation-indexed, Chilean peso-denominated monetary unit.

UTA	Unidad Tributaria Anual	Chilean annual tax unit. One UTA equals 12 UTM.

UTM	Unidad Tributaria Mensual	Chilean inflation-indexed monthly tax unit used to define fines, among other purposes.

VAD	Valor Agregado de Distribución	Value added from distribution of electricity.



VNR	Valor Nuevo de Reemplazo	The net replacement value of electricity assets.

XM	Expertos de Mercado S.A. E.S.P.	Colombian company Interconexión Eléctrica S.A. (ISA)’s subsidiary that provides system management in real time services in electrical, financial and transportation sectors.

INTRODUCTION

As used in this Report on Form 20-F, first person personal pronouns such as “we,” “us” or “our” refer to Enersis S.A. (Enersis or the Company) and our consolidated subsidiaries unless the context indicates otherwise. Unless otherwise noted, our interest in our principal subsidiaries, jointly —controlled entities and associates is expressed in terms of our economic interest as of December 31, 2012.

We are a Chilean company engaged through our subsidiaries and jointly-controlled entities in the electricity generation, transmission and distribution businesses in Chile, Brazil, Colombia, Peru and Argentina. As of the date of this Report, we own 60.0% of Empresa Nacional de Electricidad S.A. (Endesa Chile), a Chilean electricity generation company and 99.1% of Chilectra S.A. (Chilectra), a Chilean electricity distribution company. As of the same date, Endesa, S.A. (Endesa Spain), a Spanish electricity generation and distribution company, owns 60.6% of Enersis through Endesa Latinoamérica. Enel S.p.A. (Enel), an Italian generation and distribution company, owns 92.1% of Endesa Spain.

Financial Information

In this Report on Form 20-F, unless otherwise specified, references to “U.S. dollars” or “US$,” are to dollars of the United States of America; references to “pesos” or “Ch$” are to Chilean pesos, the legal currency of Chile; references to “Ar$” or “Argentine pesos” are to the legal currency of Argentina; references to “R$” or “reais” are to Brazilian reais, the legal currency of Brazil; references to “soles” are to Peruvian Nuevo Sol, the legal currency of Peru; references to “CPs” or “Colombian pesos” are to the legal currency of Colombia; references to “€” or “Euros” are to the legal currency of the European Union; and references to “UF” are to Unidades de Fomento.

The Unidad de Fomento is a Chilean inflation-indexed that is adjusted daily to reflect changes in the official Consumer Price Index, or “CPI”, of the Instituto Nacional de Estadísticas (the Chilean National Institute of Statistics). The UF is adjusted in monthly cycles. Each day in the period beginning on the tenth day of the current month through the ninth day of the succeeding month, the nominal peso value of the UF is indexed in order to reflect a proportionate amount of the change in the Chilean CPI during the prior calendar month. As of December 31, 2012, one UF was equivalent to Ch$ 22,840.75. The U.S. dollar equivalent of one UF was US$ 47.59 as of December 31, 2012, using the Observed Exchange Rate reported by the Banco Central de Chile (the “Central Bank of Chile”) as of December 31, 2012 of Ch$ 479.96 per US$ 1.00. As of February 28, 2013, one UF was equivalent to Ch$ 22,838.48. The U.S. dollar equivalent of one UF was US$ 48.29 at February 28, 2013, using the observed Exchange Rate reported by the Central Bank of Chile as of such date of Ch$ 472.96 per US$ 1.00.

Our Consolidated Financial Statements and, unless otherwise indicated, other financial information concerning Enersis included in this Report are presented in Chilean pesos. Until the year ended December 31, 2008, Enersis prepared its financial statements in accordance with generally accepted accounting principles in Chile (Chilean GAAP). Since January 1, 2009, Enersis has prepared its financial statements in accordance with International Financial Reporting Standards (IFRS), as issued by the International Accounting Standard Board (IASB).

The subsidiaries are consolidated and all their assets, liabilities, income, expenses and cash flows are included in the consolidated financial statements after making the adjustments and eliminations related to intra-group transactions.

Jointly-controlled entities, which are those that do not have a controlling shareholder but are governed by a joint management agreement, are consolidated by the proportional consolidation method. Enersis recognizes, line by line, its share of the assets, liabilities, income, expenses and cash flow of such entities, subject to accounting eliminations. Due to changes in IFRS as issued by the IASB, starting on January 1, 2013, jointly-controlled entities are no longer consolidated by the proportional consolidation method. Instead, jointly-controlled entities are recorded in our Consolidated Financial Statements under the equity method.

Investments in associates in which the Company has significant influence, are recorded in our Consolidated Financial Statements under the equity method.

For detailed information regarding subsidiaries, jointly-controlled entities and associates, see Appendix No. 1 and No. 3 to the Consolidated Financial Statements.

For the convenience of the reader, this Report contains translations of certain Chilean peso amounts into U.S. dollars at specified rates. Unless otherwise indicated, the U.S. dollar equivalent for information in Chilean pesos is based on the Observed Exchange Rate as of December 31, 2012, as defined in “Item 3. Key Information — A. Selected Financial Data — Exchange Rates” The Federal Reserve Bank of New York does not report a noon buying rate for Chilean pesos. No representation is made that the Chilean peso or U.S. dollar amounts shown in this Report could have been or could be converted into U.S. dollars or Chilean pesos, as the case may be, at such rate or at any other rate (See “Item 3. Key Information — A. Selected Financial Data — Exchange Rates”).

Technical Terms

References to “GW” and “GWh” are to gigawatts and gigawatt hours, respectively; references to “MW” and “MWh” are to megawatts and megawatt hours, respectively; references to “kW” and “kWh” are to kilowatts and kilowatt hours, respectively; references to “kV” are to kilovolts, and references to “MVA” are to megavolt amperes. Unless otherwise indicated, statistics provided in this Report with respect to the installed capacity of electricity generation facilities are expressed in MW. One TW = 1,000 GW, one GW = 1,000 MW, and one MW = 1,000 kW.

Statistics relating to aggregate annual electricity production are expressed in GWh and based on a year of 8,760 hours, except for leap years (such as 2012), which are based on 8,784 hours. Statistics relating to installed capacity and production of the electricity industry do not include electricity of self-generators. Statistics relating to our production do not include electricity consumed by us by our own generation units.

Energy losses experienced by generation companies during transmission are calculated by subtracting the number of GWh of energy sold from the number of GWh of energy generated (excluding its own energy consumption and losses on the part of the power plant), within a given period. Losses are expressed as a percentage of total energy generated.

Energy losses during distribution are calculated as the difference between total energy purchased (GWh of electricity demand, including own generation) and the energy sold (also measured in GWh), within a given period. Losses are expressed as a percentage of total energy purchased. Losses in distribution arise from illegally tapped energy as well as technical losses.

Calculation of Economic Interest

References are made in this Report to the “economic interest” of Enersis in its related companies. In circumstances where we do not directly own an interest in a related company, our economic interest in such ultimate related company is calculated by multiplying the percentage of economic interest in a directly held related company by the percentage of economic interest of any entity in the ownership chain of such related company. For example, if we own 60% of a directly held subsidiary and that subsidiary owns 40% of an associate, our economic interest in such associate would be 60% times 40%, or 24%.

Forward-Looking Statements

This Report contains statements that are or may constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements appear throughout this Report and include statements regarding our intent, belief or current expectations, including but not limited to any statements concerning:

•

our capital investment program;

•

trends affecting our financial condition or results from operations;

•

our dividend policy;

•

the future impact of competition and regulation;

•

political and economic conditions in the countries in which we or our related companies operate or may operate in the future;

•

any statements preceded by, followed by or that include the words “believes,” “expects,” “predicts,” “anticipates,” “intends,” “estimates,” “should,” “may” or similar expressions; and

•

other statements contained or incorporated by reference in this Report regarding matters that are not historical facts.

Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to:

•

changes in the regulatory framework of the electricity industry in one or more of the countries in which we operate;

•

our ability to implement proposed capital expenditures, including our ability to arrange financing where required;

•

the nature and extent of future competition in our principal markets;

•

political, economic and demographic developments in the markets in South America where we conduct our business; and

•

the factors discussed below under “Risk Factors”.

You should not place undue reliance on such statements, which speak only as of the date that they were made. Our independent public accountants have not examined or compiled the forward-looking statements, and, accordingly, do not provide any assurance with respect to such statements. You should consider these cautionary statements together with any written or oral forward-looking statements that we may issue in the future. We do not undertake any obligation to release publicly any revisions to forward-looking statements contained in this Report to reflect later events or circumstances or to reflect the occurrence of unanticipated events.

For all these forward-looking statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

RECENT DEVELOPMENTS

Capital Increase

On December 20, 2012, our shareholders approved an increase in our authorized capital through the issuance of 16,441,606,297 additional shares of common stock (the “Capital Increase”). If subscribed during the rights offering period, such shares would be issued for Ch$ 173 per share (Ch$ 8,650 per ADS) or Ch$ 2.8 trillion (US$ 5.9 billion at the Observed Exchange Rate of Ch$ 473.18 for February 22, 2013) if fully subscribed including the total value of the Endesa Spain In-Kind Contribution (as defined below). If the shares are not fully subscribed during the rights offering period, Enersis will make a subsequent offering of the unsubscribed shares within 15 days of the end of the rights offering period. The issuance price must be no less than Ch$ 173 per share if issued in such subsequent offering period. Subject to the condition described below under the heading “Condition Precedent,” Endesa Spain will subscribe for a total of 9,967,630,058 shares, in proportion to its holdings, by means of a contribution of certain assets described below under the heading “In-Kind Contribution.” Minority shareholders may subscribe for up to a total of 6,473,976,239 shares for cash. The total value of the Endesa Spain In-Kind Contribution will be Ch$ 1.7 trillion, or US$ 3.6 billion at the Observed Exchange Rate of Ch$ 473.18 for February 22, 2013. The total cash subscription if the minority shareholders subscribe in full will be Ch$ 1.1 trillion, or US$ 2.4 billion using the same exchange rate.

In connection with the Capital Increase, Enersis has filed with the United States Securities and Exchange Commission (the “SEC”) a registration statement on Form F-3 (the “Registration Statement”) and a prospectus supplement dated February 25, 2013 to the prospectus included in the Registration Statement.

Condition Precedent

The effectiveness of all contracts to subscribe for the shares offered hereby will be conditioned on the subscription by holders of rights (whether minority shareholders who receive the distribution of rights or a subsequent purchaser of rights) during the rights offering or during a subsequent offering that would include third party purchasers of at least 3,169,224,294 shares, which is the amount sufficient to permit Endesa Spain to exercise its rights to subscribe in full and, after such exercise, not own more than 65% of the outstanding capital stock of the Company as provided under our Bylaws (the “Condition Precedent”). If the Condition Precedent is not satisfied by April 10, 2013, the subscription contracts will be deemed not legally binding, and any subscription amounts tendered by any holder of rights or third party purchaser who exercised his subscription rights will be returned in full and the Capital Increase will be cancelled.

To facilitate the Condition Precedent, the following measures will be taken:

•

All subscription contracts and subscription amounts tendered by any holder of rights who exercised subscription rights or by third party purchasers will be deposited in separate escrow accounts, on the day the applicable subscription contract is executed, until the Condition Precedent is determined satisfied or to have failed, which escrow accounts will not bear interest or other returns, except that certain holders of rights or third party purchasers who are prohibited by internal policies or by applicable law from pre-paying their subscription amounts into escrow will be required to pay their respective subscription amounts to the Company by no later than close of business on the business day following

the publication of the satisfaction of the Condition Precedent described below; Endesa Spain or its designee will deposit its subscription contract and all documentation necessary to consummate the In-Kind Contribution (as defined below), in an escrow account until it is determined whether or not the Condition Precedent has been satisfied;

•

Ernst & Young has been engaged to verify the amount of money deposited in escrow account and to verify the amount of shares subscribed by certain holders of rights or third party purchasers who are prohibited by internal policies or by applicable law from pre-paying their subscription amounts into escrow. At any time during the initial rights offering or subsequent offering, if any, we may request that Ernst & Young conduct these procedures.

•

If the Condition Precedent is satisfied, the procedures set forth below regarding settlement of subscribed shares shall apply;

•

Following the satisfaction of the Condition Precedent, all subscription contracts deposited in escrow will be deemed effective and the process for the registration of the newly issued shares in the name of the respective shareholders in the Company’s shareholders registry shall commence;

•

If the Condition Precedent is determined not to have been satisfied by April 10, 2013 any subscription contracts and/or other documentation deposited in escrow and any subscription amounts tendered by holders of rights or third party purchasers will be returned to such holders of rights or third party purchasers in accordance with the terms of their respective subscription agreements (but in the case of shareholders, no later than one business day and in the case of ADS holders, as soon as reasonably practicable following the publication of the notice as to whether or not the Condition Precedent has been satisfied), and thereafter the Company shall not be liable for any indemnification obligation or other responsibility with respect to such shareholders or third party purchasers;

•

Within the three business days following the determination as to whether or not the Condition Precedent has been satisfied, the Company will publish a notice of such determination in El Mercurio de Santiago and in a Report on Form 6-K filed with the SEC;

•

If the Condition Precedent is satisfied, the Company will transmit all subscription contracts to the DCV Registros, S.A., Depósito de Valores (the Chilean Central Securities Depositary) to facilitate the registration and issuance of the shares subscribed for by such holders of rights or third party purchasers;

•

No holder of rights or third party purchaser may withdraw subscription contract and subscription amounts that have been placed into escrow unless the Condition Precedent has not been satisfied;

•

Whether or not the Condition Precedent is satisfied by the end of the rights offering period, the Company will commence a subsequent offering of any unsubscribed new shares to third party purchasers; and

•

The Condition Precedent will be satisfied if it has been met by 11:59 p.m. (Santiago, Chile time) on the 15th day following the end of the preemptive rights subscription period, and the subscription contracts and subscription amounts tendered by shareholders exercising their subscription rights or by third party purchasers may remain in escrow until the end of such period.

Any unsubscribed shares remaining after the rights offering period and the subsequent offering period will not be further offered or sold.

The In-Kind Contribution

Endesa Spain will make an in-kind contribution (the “In-Kind Contribution”) of all of its interests in Cono Sur Participaciones, S.L.U. (“Cono Sur”), a wholly owned subsidiary that holds direct and indirect interests in a total of 25 generation, transmission, distribution and energy holding companies (the Portfolio Companies) in Chile, Brazil, Colombia, Peru and Argentina, of which sixteen are operating companies. The Company already consolidates the financial results of twelve of the sixteen operating companies by virtue or majority ownership interest or voting control. The remaining four operating companies included as part of the In-Kind Contribution are not material, as they are holding or service companies.

On December 20, 2012, the Board of Directors presented the In-Kind Contribution for the consideration and approval of shareholders. The vote of two-thirds of the outstanding shares was required to approve the In-Kind Contribution. Shareholders holding 82% of the outstanding shares approved the In-Kind Contribution at a value of US$ 3,615 million, based on an exchange rate of Ch$ 477 per U.S. dollar.

PART I

Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

A. Selected Financial Data

The following summary of consolidated financial data should be read in conjunction with our audited Consolidated Financial Statements included in this Report. The consolidated financial data as of and for the years ended December 31, 2009 and 2008 are derived from our audited consolidated financial statements not included in this Report. Our audited consolidated financial statements as of and for the years ended December 31, 2012, 2011, 2010 and 2009 were prepared in accordance with IFRS, as issued by the IASB. Our audited consolidated financial statements as of and for the year ended December 31, 2008 were prepared in accordance with Chilean GAAP. The financial data as of and for each of the years in the five year period ended December 31, 2012 in the table below are presented in Chilean pesos.

Amounts are expressed in millions except for ratios, operating data, shares and ADS (American Depositary Shares) data. For the convenience of the reader, all data presented in U.S. dollars in the following summary, as of and for the year ended December 31, 2012, are translated at the Observed Exchange Rate for that date of Ch$ 479.96 per US$ 1.00. No representation is made that the Chilean peso or U.S. dollar amounts shown in this Report could have been or could be converted into U.S. dollars or Chilean pesos, at such rate or at any other rate. For more information concerning historical exchange rates, see “Exchange Rates” below.

The following tables set forth the selected consolidated financial data of Enersis for the periods indicated and the operating data of subsidiaries:


	As of and for the year ended December 31,
	2012 (1)			2012			2011			2010			2009			2008
	US$ Million									Ch$ Million
Consolidated Income Statement Data
Revenues		13,705			6,577,667			6,534,880			6,563,581			6,472,056			6,579,945
Operating Expense (2)		(10,586	)		(5,080,702	)		(4,968,569	)		(4,859,280	)		(4,544,611	)		(4,716,294	)

Operating Income		3,119			1,496,965			1,566,311			1,704,301			1,927,445			1,863,651
Financial Income (Expense), Net		(450	)		(216,189	)		(236,585	)		(270,605	)		(309,256	)		(419,366	)
Total gain (loss) on sale of non-current assets not held for sale		29			14,094			(5,853	)		11,711			50,502			2,503
Other non-operating income		22			10,583			9,504			1,288			2,374			3,297

Net Income Before Tax		2,720			1,305,453			1,333,377			1,446,695			1,671,065			1,450,085
Income tax		(858	)		(411,891	)		(460,837	)		(346,006	)		(359,737	)		(415,903	)

Net Income		1,862			893,562			872,540			1,100,689			1,311,328			1,034,182
Net income attributable to: Shareholders of Enersis		786			377,351			375,471			486,227			660,231			507,590
Net income attributable to: Non-controlling interests		1,076			516,211			497,069			614,462			651,097			526,592

Net Income (loss) from continuing operations per Share (Ch$ / US$)		0.02			11.56			11.50			14.89			20.22			15.55
Net Income (loss) from continuing operations per ADS (Ch$ / US$)		1.20			577.85			574.97			744.58			1.011.04			777.29
Net income (loss) per Share (Ch$/US$ per share)		0.02			11.56			11.50			14.89			20.22			15.55
Net income (loss) per ADS (Ch$/US$ per ADS)		1.20			577.85			574.97			744.58			1.011.04			777.29
Cash Dividends per Share (Ch$/ US$ per share)		0.01			5.75			7.45			4.64			7.02			4.95
Cash Dividends per ADS (Ch$/ US$ per ADS)		0.60			287.49			372.50			232.00			351.00			247.50
Capital Stock		5,886			2,824,883			2,824,883			2,824,883			2,824,883			2,824,883
Number of shares of common stock (thousands)					32,651,166			32,651,166			32,651,166			32,651,166			32,651,166
Number of ADS (thousands)					73,894			82,456			82,320			81,303			71,267

Consolidated Balance Sheet Data
Total Assets		27,748			13,317,834			13,733,871			13,005,845			13,210,140			13,781,176
Non-Current Liabilities		8,278			3,972,953			4,377,183			4,084,540			4,637,749			5,049,265
Equity Attributable to Shareholders of Enersis		8,113			3,893,799			3,895,729			3,735,545			3,518,480			3,091,315
Equity Attributable to Non-controlling interests		6,396			3,069,970			3,000,425			2,778,483			2,858,524			2,937,816
Capital Stock (3)		5,747			2,983,642			2,983,642			2,983,642			2,983,642			2,983,642

Other Consolidated Financial Data
Capital Expenditures (Capex) (4)		1,496			717,981			686,006			701,341			736,474			781,542
Depreciation, amortization and impairment losses		1,013			485,960			561,057			557,391			539,655			438,064

(1)	Solely for the convenience of the reader, Chilean peso amounts have been translated into U.S. dollars at the exchange rate of Ch$ 479.96 per U.S. dollar, the Observed Exchange Rate for December 31, 2012.

(2)	Operating Expense include Selling and Administration Expense.

(3)	Includes share premium.

(4)	Capex figures represent actual payments for each year.


	As of and for the year ended December 31,
	2012			2011			2010			2009			2008
OPERATING DATA OF SUBSIDIARIES

Chilectra (Chile)
Electricity Sold (GWh)		14,445			13,697			13,098			12,585			12,535
Number of Customers (thousands)		1,659			1,638			1,610			1,579			1,534
Total Energy Losses (%) (1)		5.4	%		5.5	%		5.8	%		6.1	%		5.9	%

Edesur (Argentina)
Electricity Sold (GWh)		17,738			17,233			16,759			16,026			16,160
Number of Customers (thousands)		2,389			2,389			2,353			2,305			2,262
Total Energy Losses (%) (1)		10.6	%		10.5	%		10.5	%		10.5	%		10.6	%

Ampla (Brazil)
Electricity Sold (GWh)		10,816			10,223			9,927			9,394			9,119
Number of Customers (thousands)		2,712			2,644			2,571			2,522			2,466
Total Energy Losses (%) (1)		19.6	%		19,7	%		20.5	%		21.2	%		20.2	%

Coelce (Brazil)
Electricity Sold (GWh)		9,878			8,970			8,850			7,860			7,571
Number of Customers (thousands)		3,338			3,224			3,095			2,965			2,842
Total Energy Losses (%) (1)		12.6	%		11.9	%		12.1	%		11.6	%		11.7	%

Codensa (Colombia)(2)
Electricity Sold (GWh)		12,972			12,552			12,141			11,837			11,822
Number of Customers (thousands)		2,588			2,496			2,429			2,361			2,285
Total Energy Losses (%) (1)		7.3	%		7.8	%		8.2	%		8.2	%		8.1	%

EEC (Colombia) (3)
Electricity Sold (GWh)		392			305			373			277			n.a.
Number of Customers (thousands)		125			121			117			115			n.a.
Total Energy Losses (%) (1)		13.4	%		20.2			17.7	%		15.2	%		n.a.	%

Edelnor (Peru)
Electricity Sold (GWh)		6,863			6,572			6,126			5,716			5,599
Number of Customers (thousands)		1,203			1,144			1,098			1,061			1,028
Total Energy Losses (%) (1)		8.2	%		8.2	%		8.3	%		8.1	%		8.2	%

Endesa Chile
Installed capacity in Chile (MW)		5,961			5,611			5,611			5,650			5,283
Installed capacity in Argentina (MW)		3,652			3,652			3,652			3,652			3,652
Installed capacity in Colombia (MW)		2,914			2,914			2,914			2,895			2,895
Installed capacity in Peru (MW)		1,657			1,668			1,668			1,667			1,467
Production in Chile (GWh) (4)		20,194			20,722			20,914			22,239			21,267
Production in Argentina (GWh) (4)		11,289			10,801			10,940			11,955			10,480
Production in Colombia (GWh) (4)		13,294			12,090			11,283			12,674			12,905
Production in Peru (GWh) (4)		8,740			9,153			8,466			8,163			8,102

Endesa Brasil
Installed capacity in Brazil (MW)		987			987			987			987			987
Production in Brazil (GWh) (4)		5,177			4,155			5,095			3,319			3,379

(1)

Energy losses are calculated as the difference between total energy purchased (GWh of electricity demand, including own generation) and the energy sold (GWh), within a given period. Losses are expressed as a percentage of total energy purchased. Losses in distribution arise from illegally tapped energy as well as technical failures.

(2)	In February 2009, Codensa, our Colombian distribution subsidiary, acquired approximately 49% of DECSA. On March 13, 2009, DECSA acquired 82.3% of EEC. Beginning in 2010, we started separately presenting the information concerning EEC, a jointly-controlled company of Codensa.

(3)	The results for 2009 include the period of April through December.

(4)	Energy production is defined as total generation minus energy consumption and technical losses within our own power plants.

Exchange Rates

Fluctuations in the exchange rate between the Chilean peso and the U.S. dollar will affect the U.S. dollar equivalent of the peso price of our shares of common stock, without par value (the “Shares” or the “Common Stock”), on the Bolsa de Comercio de Santiago (the “Santiago Stock Exchange”), the Bolsa Electrónica de Chile (the “Chilean Electronic Stock Exchange”) and the Bolsa de Corredores de Valparaíso (the “Valparaíso Stock Exchange”) (collectively, the “Chilean Stock Exchanges”). These exchange rate fluctuations will likely affect the price of our ADSs and the conversion of cash dividends relating to the Shares represented by ADSs from Chilean pesos to U.S. dollars. In addition, to the extent that significant financial liabilities of the Company are denominated in foreign currencies, exchange rate fluctuations may have a significant impact on earnings.

In Chile, there are two currency markets, the Formal Exchange Market (Mercado Cambiario Formal) and the Informal Exchange Market (Mercado Cambiario Informal). The Formal Exchange Market is comprised of banks and other entities authorized by the Central Bank of Chile. The Informal Exchange Market is comprised of entities that are not expressly authorized to operate in the Formal Exchange Market, such as certain foreign exchange houses and travel agencies, among others. The Central Bank of Chile has the authority to require that certain purchases and sales of foreign currencies be carried out on the Formal Exchange Market. Both the Formal and Informal Exchange Markets are driven by free market forces. Current regulations require that the Central Bank of Chile be informed of certain transactions and that they be effected through the Formal Exchange Market.

The U.S. dollar observed exchange rate (dólar observado) (the “Observed Exchange Rate”), which is reported by the Central Bank of Chile and published daily in its web page, is the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market. Nevertheless, the Central Bank of Chile may intervene by buying or selling foreign currency on the Formal Exchange Market to attempt to maintain the Observed Exchange Rate within a desired range.

The Informal Exchange Market reflects transactions carried out at an informal exchange rate (the “Informal Exchange Rate”). There are no limits imposed on the extent to which the rate of exchange in the Informal Exchange Market can fluctuate above or below the Observed Exchange Rate. Foreign currency for payments and distributions with respect to the ADSs may be purchased either in the Formal or the Informal Exchange Market, but such payments and distributions must be remitted through the Formal Exchange Market.

The Federal Reserve Bank of New York does not report a noon buying rate for Chilean pesos. As of December 31, 2012, the U.S. dollar exchange rate used by us was Ch$ 479.96 per US$ 1.00.

The following table sets forth the annual low, high, average and period-end Observed Exchange Rate for U.S. dollars for the periods set forth below, as reported by the Central Bank of Chile:


	Daily Observed Exchange Rate (Ch$ per US$) (1)
Year ended December 31,	Low (2)		High (2)		Average (3)		Period-end
2012		469.65		519.69		486.31		479.96
2011		455.91		533.74		483.45		519.20
2010		468.01		549.17		510.38		468.01
2009		491.09		643.87		554.22		507.10
2008		431.22		676.75		530.48		636.45
Month ended
February 2013		470.67		473.60		n.a.		472.96
January 2013		470.67		475.47		n.a.		471.44
December 2012		474.36		481.28		n.a.		479.96
November 2012		476.20		484.48		n.a.		480.39
October 2012		471.54		481.98		n.a.		480.59
September 2012		469.65		481.11		n.a.		473.77

Source: Central Bank of Chile.

(1)

Nominal figures.

(2)

Exchange rates are the actual low and high, on a day-by-day basis for each period.

(3)

The average of the exchange rates on the last day of each month during the period.

As of March 19, 2013, the U.S. dollar exchange rate was Ch$ 472.34 per US$ 1.00.

Calculation of the appreciation or devaluation of the Chilean peso against the U.S. dollar in any given period is made by determining the percent change between the reciprocals of the Chilean peso equivalent of US$ 1.00 at the end of the preceding period and the end of the period for which the calculation is being made. For example, to calculate the appreciation of the year-end Chilean peso in 2012, one determines the percent change between the reciprocal of Ch$ 519.2 (the value of one U.S. dollar as of December 31, 2011) and the reciprocal of Ch$ 479.96 (the value of one U.S. dollar as of December 31, 2012). In this example, the percentage change between 0.001926 (the reciprocal of Ch$ 519.20) and 0.002084 (the reciprocal of Ch$ 479.96) is 8.2%, which represents the 2012 year-end appreciation of the Chilean peso against the 2011 year-end U.S. dollar. A positive percentage change means that the Chilean peso appreciated against the U.S. dollar, while a negative percentage change means that the Chilean peso devaluated against the U.S. dollar.

The following table sets forth the period-end rates for U.S. dollars for the years ended December 31, 2008 through December 31, 2012 and through the date indicated in the table below, based on information published by the Central Bank of Chile.


	Period End		Appreciation (Devaluation) (1)
Chilean Peso Equivalent of US$ 1
Year Ended:
December 31, 2012		479.96		8.2	%
December 31, 2011		519.20		(9.9	)%
December 31, 2010		468.01		8.4	%
December 31, 2009		507.10		25.5	%
December 31, 2008		636.45		(21.9	)%

Source: Central Bank of Chile.

(1)	Calculated based on the variation of period-end exchange rates.

B. Capitalization and Indebtedness.

Not applicable.

C. Reasons for the Offer and Use of Proceeds.

Not applicable.

D. Risk Factors.

A financial crisis in any region worldwide can have a significant impact in the countries in which we operate, and consequently, may adversely affect our operations, as well as our liquidity.

The five countries in which we operate are vulnerable to external shocks, which could cause significant economic difficulties and affect their growth. If any of these economies experience lower than expected economic growth or a recession, it is likely that our customers will demand less electricity, which could adversely affect our results of operations and financial condition. Furthermore, some of our customers may experience difficulties in paying their electricity bills, and an increase in uncollectible accounts would also adversely affect our results.

In addition, a financial crisis and its disruptive effect on the financial industry can have an adverse impact on our ability to obtain new bank loans under normal terms and conditions. Our ability to tap the capital markets in the five countries where we operate, as well as the international capital markets for other sources of liquidity, may also be diminished, or such financing may be available only at higher interest levels. Reduced liquidity could, in turn, affect our capital expenditures, our long-term investments and acquisitions, our growth prospects, and our dividend payout policy.

A financial crisis in the Euro Area or a European sovereign debt crisis may have an adverse effect on our liquidity.

Global economic growth decreased 0.4% in the Euro area in 2012 and is now expected to contract by 0.2% in 2013. The Euro area continues to represent a large downside risk for the world economy. The risk of prolonged stagnation in the Euro area may increase. Among the countries that are particularly at risk are Spain and Italy, home of our parent companies, Endesa Spain and Enel, respectively.

We carry out a significant portion of our bank financings and derivative hedges with European banks. Our European counterparty risk takes into account loans and derivatives accounted for either in the parent bank entities headquartered in Europe or in any of their subsidiaries or agencies outside Europe. In general terms, European banks who act through their foreign subsidiaries, agencies and representative offices also take an aggregated group risk to counterparty exposure, both theirs and ours. If any of the European banks with which we have significant relationships were to encounter severe financial difficulties, our access to bank loans would be significantly curtailed, and would probably lead to an increase in our interest expense.

As of December 31, 2012, US$ 487 million of our outstanding bank debt and US$ 1,717 million of the notional amount of our derivative hedges are with bank groups whose parent companies are headquartered in Europe. The derivative hedges deals with both currency swaps and interest rates swaps, though the most significant component is the currency hedge for the inflation-indexed Chilean peso (the UF) against the U.S. dollar. As of December 31, 2012, these derivative hedges had a mark to market value of US$ 389 million against us. Of the amounts mentioned above, 82% of our bank debt and 76% of the notional amount of our derivatives have been contracted with Spanish banks. A severe financial disruption affecting these Spanish banks could therefore have an adverse effect on us, especially regarding our bank lenders. (See “Item 5. Operating and Financial Review and Prospects. — B. Liquidity & Capital Resources” and “Item 11. Quantitative and Qualitative Disclosures about Market Risk”).

South American economic fluctuations are likely to affect our results from operations and financial condition, as well as the value of our securities.

All of our operations are located in five South American countries. Accordingly, our consolidated revenues are sensitive to the performance of South American economies as a whole. If local, regional or worldwide economic trends adversely affect the economy of any of the five countries in which we have investments or operations, our financial condition and results from operations could be adversely affected. Moreover, we have investments in relatively risky countries such as Argentina. Cash generation from our subsidiaries located in Argentina has been lower than expected and in some cases has been insufficient to permit them to comply with their obligations.

A substantial portion of our operations are located in Brazil and Chile and 67% of our operating revenues in 2012 were derived from our operations in these countries, making our financial condition and results of operations particularly dependent on their performance. In 2012, Brazilian GDP increased 1.6% compared to a 3.8% increase in 2011, based on the consensus forecast according to the Brazilian Central Bank. Future developments in these economies may impair our ability to proceed with our strategic plans and adversely impact our financial condition or results of operations.

In addition, the South American financial and securities markets are, to varying degrees, influenced by economic and market conditions in other countries. Although economic conditions are different in each country, investor reaction to developments in one country may have a significant contagion effect on the securities of issuers in other countries, including Brazil and Chile. Brazilian and Chilean financial and securities markets may be adversely affected by events in other countries and such effects may affect the value of our securities.

Certain South American economies have been characterized by frequent and occasionally drastic intervention by governmental authorities, which may adversely affect our business and financial results.

Governmental authorities have changed monetary, credit, tariff, tax and other policies to influence the course of the economies of Argentina, Brazil, Colombia and Peru. To a lesser extent, the Chilean government has also exercised and continues to exercise a substantial influence over many aspects of the private sector, which may result in changes to economic or other policies. These governmental actions, intended to control inflation and affect other policies, have often involved wage, price and tariff rate controls as well as other interventionist measures. For example, Argentina froze bank accounts and imposed capital restrictions in 2001, nationalized the private sector pension funds in 2008, and used Central Bank reserves of the Argentine Treasury in order to pay down indebtedness maturing in 2010. In 2010, Colombia imposed an equity tax to finance reconstruction to repair damage caused by severe flooding, which resulted in an accrual booked in January 2011 for taxes payable in 2011-2014. For additional information please see “Item 5. Operating and Financial Review and Prospects — A. Operating Results — 2. Enersis’ Results from Operations for the Years ended December 31, 2012 and December 31, 2011 — Operating Costs”).

Changes in the policies of these governmental authorities with respect to tariff rates, exchange controls, regulations and taxation could adversely affect our business and financial results, reducing our profitability, as could inflation, devaluation, social instability and other political, economic or diplomatic developments, including the response by governments in the region to these circumstances.

Our electricity business is subject to risks arising from natural disasters, catastrophic accidents and acts of terrorism, which could adversely affect our operations, earnings and cash flow.

Our primary facilities include power plants, transmission and distribution assets, pipelines, LNG terminals and re-gasification plants, storage and chartered LNG tankers. Our facilities may be damaged by earthquakes, flooding, fires, other catastrophic disasters arising from natural or accidental human causes, as well as acts of terrorism. We could experience severe business disruptions, significant decreases in revenues based on lower demand arising from catastrophic events, or significant additional costs to us not otherwise covered by business interruption insurance clauses. There may be an important time lag between a major accident or catastrophic event and the final reimbursement from our insurance policies, which typically carry non-recoverable deductible amounts, and in any event are subject to caps per event. For further detail, please see “Item 4. Information on the Company — D. Property, Plants and Equipment.”

As an example, on February 27, 2010, Chile experienced a major earthquake, with a magnitude of 8.8 on the Richter scale, in the Bío-Bío Region, followed by a very destructive tsunami. Our Bocamina and Bocamina II thermal generation units, which are located near the epicenter, sustained significant damage as a result of the earthquake.

We are subject to financing risks, such as those associated with funding our new projects and capital expenditures, risk related to refinancing our maturing debt and we are also subject to debt covenant compliance, all of which could adversely affect our liquidity.

As of December 31, 2012, our financial debt totaled US$ 7,497 million.

Our debt had the following maturity timetable:

•

US$ 1,396 million in 2013;

•

US$ 2,216 million in the 2014-2015 period;

•

US$ 1,451 million in the 2016-2017 period; and

•

US$ 2,434 million thereafter.

Set forth below is a breakdown by country for financial debt maturing in 2013:

•

US$ 500 million — Chile;

•

US$ 327 million — Argentina;

•

US$ 231 million — Brazil;

•

US$ 211 million — Colombia; and

•

US$ 127 million — Peru.

Some of our debt agreements are subject to financial covenants. They also contain affirmative and negative covenants, events of default or mandatory prepayments for contractual breaches, including certain changes of control, and for material mergers and divestments, among other provisions. A significant portion of our financial indebtedness is subject to cross default provisions, with different definitions, criteria, materiality thresholds, and applicability as to the subsidiaries that could give rise to such a cross default.

In the event that we or our subsidiaries breach any of these material contractual provisions, our creditors and bond holders may demand immediate repayment, and a significant portion of our indebtedness could become due and payable.

We may be unable to refinance our indebtedness or obtain such refinancing on terms acceptable to us. In the absence of such refinancing, we could be forced to dispose of assets in order to make up for any shortfall in the payments due on our indebtedness under circumstances that might not be favorable to obtaining the best price for such assets. Furthermore, assets may not be sold quickly enough, or for amounts sufficient, to enable us to make such payments.

We may also be unable to raise funds required to finish our projects under development or under construction. Market conditions prevailing at the moment we require these funds or other unforeseen project costs can compromise our ability to finance these projects and expenditures.

As of the date of this Report, Argentina continues to be the country with the highest refinancing risk. As of December 31, 2012, the third-party financial debt of our Argentine subsidiaries amounted to US$ 376 million. As a matter of policy for all of our Argentine subsidiaries as long as fundamental issues concerning the electricity sector remain unresolved, we intend to roll over our outstanding Argentine debt to the extent we are able to do so. If our creditors do not continue to accept rolling over debt when it becomes due, and we are unable to refinance such obligations, we may default on such indebtedness.

Our Argentine subsidiary, Endesa Costanera, did not make an installment payment due on March 30, 2012 of US$ 17.6 million (which included US$ 4.3 million in interest expense) and another installment payment due on September 30, 2012 of US$ 17 million (which included US$ 4.5 million in interest expense) under the terms of a supplier credit agreement with Mitsubishi Corporation (“MC”) originally entered into in 1996. In addition, Endesa Costanera will not be able to pay the installment payment which matures on March 31, 2013 of US$ 15.4 million (which includes US$ 4.2 million in interest expense). The aggregate principal amount accrued under the supplier credit agreement as of December 31, 2012, including capitalized interest, was US$ 141 million. Endesa Costanera has experienced difficulties in making timely payments under its agreement with MC on a recurring basis since the Argentine crisis of 2002, but had in the past received waivers from MC expressing its willingness to renegotiate payments. The relevant terms of the supplier credit provide for a 180-day grace period for each payment, and the first grace period expired on September 26, 2012. As of the date of this Report, Endesa Costanera has not received any waivers for the payments past due. To declare the indebtedness due and payable, MC must formally accelerate the debt with ten days prior notice. If MC chooses to do so, the amount payable would be the full principal of US$ 141 million. As of the date of this Report, we have not received any acceleration notice and negotiations to restructure the indebtedness are on-going. As of December 31, 2012, Endesa Costanera had a negative net worth and a deficit in its working capital, in both cases attributable to its inability to obtain tariff adjustments that truly reflect real generation costs. Defaults and cross defaults at the Endesa Costanera level do not trigger cross default provisions under indebtedness of Enersis or any of our Chilean subsidiaries. (See Note 34.5 to our Consolidated Financial Statements).

With the exception of our Argentine subsidiaries, our companies have access to existing credit lines sufficient to satisfy all of their present working capital needs. Access to the capital markets on the part of our Argentine subsidiaries has been very limited due to the difficult financial situation still prevailing in Argentina (particularly in the utilities sector), the poor capital markets environment due to the shortage of off-shore financing, the nationalization of the pension fund system and, in general, higher risk associated with lending to Argentine utilities as a consequence of the regulatory framework. (See “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework.— Argentina — Regulatory Developments: the industry after the Public Emergency Law” and “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources.”) For more information on covenants, cross default and relevant provisions of our credit facilities, see “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources.”

We may not be able to effect suitable investments, alliances and acquisitions.

On an ongoing basis, we review acquisition prospects that would augment our market coverage or complement our existing businesses. However, we cannot assure you that we will be able to identify and consummate suitable acquisition transactions in the future. The acquisition and integration of independent companies or companies that we do not control is generally a complex, costly and time-consuming process and requires significant efforts and expenditures. If we consummate an acquisition, it could result in the incurrence of substantial debt and assumption of unknown liabilities, the potential loss of key employees from the acquired company, amortization expenses related to tangible assets and the diversion of our management’s attention from other business concerns. In addition, any delays or difficulties encountered in connection with acquisitions and the integration of multiple operations could have a material adverse effect on our business, financial condition or results of operations.

Since our generation business depends heavily on hydrological conditions, drought conditions may hurt our profitability.

Approximately 57% of our consolidated installed generation capacity in 2012 was hydroelectric. Accordingly, extreme hydrological conditions may affect our business and may have an adverse effect on our results. In the last few years, regional hydrology has been affected by two climactic phenomena — El Niño and La Niña — that influence rainfall regularity and may lead to droughts. The effects of El Niño or La Niña can unevenly affect the hydrology of the countries where we operate.

During periods of drought, thermal plants, such as ours that use natural gas, fuel oil or coal as a fuel, are dispatched more frequently. Operating costs of thermal plants might be considerably higher than those of hydroelectric plants. Our operating expenses increase during these periods, and depending on our commercial obligations, we may have to buy electricity from the spot market in order to comply with our contractual supply obligations. The cost of these electricity purchases may exceed the price at which we sell contracted electricity, thus producing losses from those contracts. For further information on hydrology please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company — a. Generation Business.”

If British Gas fails to make any of the natural gas deliveries it is obliged to make to us, we may incur replacement costs that we may not be able to recoup.

In order to mitigate exposure to variations in fuel prices, certain of our subsidiaries have entered into fuel supply contracts to provide part of the fuel needed to operate their thermal generation facilities. As a part of this initiative, Endesa Chile, through a subsidiary, entered into a Flexible Liquefied Natural Gas (“LNG”) Sale and Purchase Agreement with a subsidiary of British Gas (“BG”) on May 31, 2007, pursuant to which BG is obligated to provide 2.2 million m³ of LNG per day until 2030. Endesa Chile changed its supply arrangements, as permitted under the contract, effective January 1, 2013, which resulted in a significant reduction in the price of LNG that BG is obligated to deliver under the contract because the reference price changed from the Brent index to the

Henry Hub index. BG urged Endesa Chile to renegotiate the price and proposed a material increase in the price of LNG post-January 1, 2013, but the contract does not provide for contractual renegotiation under these circumstances. Despite negotiations between Endesa Chile and BG to resolve the issue, the parties were unable to reach an agreement and BG notified Endesa Chile that some shipments of LNG (up to 50% of the contract quantity) in 2013, including the shipment of LNG scheduled for April 1, 2013, would not be delivered.

Most of Endesa Chile’s LNG consumption is covered by the BG contract. If BG fails to deliver LNG, Endesa Chile will incur extra costs in fuel purchases on the spot market in order to comply with its generation facilities’ requirements. Endesa Chile would also be forced to initiate arbitration proceedings under the contract to compel BG to satisfy its indemnification obligations so that Endesa Chile may recover the additional costs incurred in replacing the undelivered LNG shipments by BG.

Governmental regulations may adversely affect our business and have already done so in Argentina.

We are subject to extensive regulation of tariffs and other aspects of our business in the five countries in which we operate, and these regulations may adversely affect our profitability. For example, the Chilean government can impose electricity rationing during drought conditions or prolonged failures in power facilities. If, during rationing, we are unable to generate enough electricity to comply with our contractual obligations, we may be forced to buy electricity in the pool market at the spot price, since even a severe drought does not constitute a force majeure event. The spot price may be significantly higher than our costs to generate the electricity and can be as high as the “cost of failure” set by the National Energy Commission, or the CNE. This “cost of failure,” which is updated semiannually by the CNE, is a measurement of how much final users would pay for one extra MWh under rationing conditions. If we are unable to buy enough electricity in the pool market to comply with all of our contractual obligations, then we would have to compensate our regulated customers for the electricity we failed to provide at the rationed price. If material rationing policies are imposed by regulatory authorities in any of the countries in which we operate, our business, financial condition and results from operations may be affected adversely in a material way. Rationing periods may occur in the future, and consequently our generation subsidiaries may be required to pay regulatory penalties if such subsidiaries fail to provide adequate service under such conditions.

Governmental authorities may also delay the distribution tariff review process, or tariff adjustments determined by governmental authorities may not be sufficient to pass through our costs (as has been the case with Edesur, our Argentine distribution subsidiary). Similarly, the regulatory framework for the electricity sector in a jurisdiction may affect the ability of our generation companies (such as Endesa Costanera, our electricity generation company) to collect revenues sufficient to offset our costs.

The inability of any company in our consolidated group of companies to collect revenues sufficient to cover operating costs may affect the ability of the affected company to operate as a going concern and may otherwise have an adverse effect on our business, assets, financial results and operations. For additional information on Edesur and Endesa Costanera, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results — 2. Enersis’ Results from Operations for the Years ended December 31, 2012 and December 31, 2011.”

In addition, changes in the regulatory framework, including changes that if adopted would significantly affect our operations, are often submitted to the legislators and administrative authorities in the countries in which we operate and, if approved, could have a material adverse impact on our business. For instance, in 2005 there was a change in the water rights’ law in Chile that requires us to pay for unused water rights. (See “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework — Chile — Water Rights.”)

Regulatory authorities may impose fines on our subsidiaries.

Our electricity businesses may be subject to regulatory fines for any breach of current regulations, including energy supply failure, in the five countries in which we operate. In Chile, such fines may range from 1 Unidad Tributaria Mensual (UTM), or US$ 84, to 10,000 Unidades Tributarias Anuales (UTA), or US$ 10.1 million, in each case using the UTM, UTA and foreign exchange rate as of December 31, 2012. In Peru, fines can reach a maximum of 1,400 Unidad Impositiva Tributaria (UIT) or US$ 2.0 million as of December 31, 2012; in Colombia fines may range from US$ 2,900 to US$ 0.6 million; in Argentina, there is no maximum limit for the fines and in Brazil fines may be imposed for up to 2.0% of the concessionaire’s revenues.

Our electricity subsidiaries, supervised by their local regulatory entities, may be subject to these fines in cases where, in the opinion of the regulatory entity, operational failures that affect the regular energy supply to the system are the fault of the company; for instance, when the agents are not coordinated with the system operation. Also, our subsidiaries may be required to pay fines or to compensate customers if those subsidiaries are unable to deliver electricity to them even if such failure is due to forces outside of our control.

For example, in January 2011, ENRE imposed fines on Edesur in the amount of US$ 16.2 million due to a blackout that occurred in Buenos Aires during the last days of December 2010, including the compensation to end users with respect to the blackout. In September 2011, SEF imposed fines totaling 2,782 UTA, or US$ 2.5 million, on Endesa Chile, Pehuenche and Chilectra due to a blackout that occurred in the Metropolitan Region in March 2010. In 2012, the Agência Reguladora de Serviços Públicos Delegados do Estado do Ceará imposed fines on Coelce, totaling US$ 17.4 million, due to failures in the technical and commercial operation of the company and ANEEL imposed a fine of US$ 10.3 million due to findings in the fiscalization of the Regulatory Asset Base. For further information on fines please refer to “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework.”

We depend in part on payments from our subsidiaries, jointly-controlled entities and associates to meet our payment obligations.

As a holding company, we have no significant assets other than the stock of our subsidiaries. Our ability to pay our obligations depends on cash from dividends, loans, interest payments, capital reductions and other distributions from our subsidiaries and equity affiliates. The ability of our subsidiaries and equity affiliates to pay dividends, interest payments, loans and other distributions to us is subject to legal constraints such as dividend restrictions, fiduciary duties, contractual limitations and foreign exchange controls that may be imposed in any of the five countries where they operate.

Historically, we have been able to access the cash flows of our Chilean subsidiaries, but we have not been similarly able to access at all times the cash flows of our non-Chilean operating subsidiaries due to government regulations, strategic considerations, economic conditions and credit restrictions.

Our future results from operations outside Chile may continue to be subject to greater economic and political uncertainties than what we have experienced in Chile, thereby reducing the likelihood that we will be able to rely on cash flows from operations in those entities to repay our debt.

Dividend Limits and Other Legal Restrictions. Some of our non-Chilean subsidiaries are subject to legal reserve requirements and other restrictions on dividend payments. Also, other legal restrictions, such as foreign currency controls, may limit the ability of our non-Chilean subsidiaries and equity affiliates to pay dividends and make loan payments or other distributions to us. In addition, the ability of any of our subsidiaries which are not wholly-owned to distribute cash to us may be limited by the fiduciary duties of the directors of such subsidiaries to their minority shareholders. Furthermore, some of our subsidiaries may be forced by local authorities, according to applicable regulation, to diminish or eliminate dividend payments, such as restrictions for distributing dividends faced by our Argentine subsidiary, Edesur, since 2009. As a consequence of such restrictions, our subsidiaries could, under certain circumstances, be prevented from distributing cash to us.

Contractual Constraints. Distribution restrictions included in some credit agreements of our subsidiaries Endesa Costanera, El Chocón and Endesa Fortaleza may prevent dividend distributions and other distributions to shareholders if they are not in compliance with certain financial ratios. Generally, companies are not allowed to make any kind of distribution in case of default on credit agreements.

Operating Results of Our Subsidiaries. The ability of our subsidiaries and equity affiliates to pay dividends or make loan payments or other distributions to us is limited by their operating results. To the extent that the cash requirements at any of our subsidiaries exceed available cash, such subsidiary will not be able to make cash available to us. For further discussion see “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources” and Note 24.4 to our Consolidated Financial Statements.

Foreign exchange risks may adversely affect our results, and the U.S. dollar value of dividends payable to ADS holders.

Most South American currencies in which we and our subsidiaries operate have been subject to large devaluations and appreciations against the U.S. dollar and may be subject to significant fluctuations in the future.

Historically, a significant portion of our consolidated indebtedness has been denominated in U.S. dollars and, while a substantial portion of our operating cash flows are linked to U.S. dollars, we generally have been and will continue to be materially exposed to fluctuations of our local currencies against the U.S. dollar because of time lags and other limitations to peg our tariffs to the U.S. dollar.

Because of this exposure, the cash generated by our subsidiaries can decrease substantially when local currencies devalue against the U.S. dollar. Future volatility in the exchange rate of the currencies in which we receive revenues or incur expenditures may affect our financial condition and results from operations. For more information on the risks associated with foreign exchange rates, see “Item 11. Quantitative and Qualitative Disclosures About Market Risk.”

As of December 31, 2012, the amount of Enersis’ total consolidated financial debt was US$ 7,497 million (net of currency hedging instruments). Of this amount, US$ 2,855 million, or 38%, was denominated in U.S. dollars and US$ 708 million in Chilean pesos. In addition to the U.S. dollar and the Chilean peso, our foreign currency denominated consolidated indebtedness included the equivalent of:

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US$ 2,179 million in Colombian pesos;

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US$ 1,129 million in reais;

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US$ 466 million in soles; and

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US$ 160 million in Argentine pesos.

This totals an aggregate of US$ 3,935 million in currencies other than U.S. dollars or Chilean pesos. For more information on the risks associated with foreign exchange rates, see “Item 11. Quantitative and Qualitative Disclosures About Market Risk.”

For the twelve-month period ended December 31, 2012, our operating cash flows were US$ 3,227 million (before consolidation adjustments) of which:

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US$ 1,114 million, or 35%, were generated in Brazil;

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US$ 1,031 million, or 32%, in Colombia;

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US$ 461 million, or 14%, in Chile;

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US$ 371 million, or 11%, in Peru; and

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US$ 249 million, or 8%, in Argentina

Although we generate revenues and incur debt in these same currencies, we believe that we are subject to risk in terms of our foreign exchange exposure to these four currencies. The most material case is that of our Argentine generation companies, where most of our debt is denominated in U.S. dollars while our revenues are mostly in Argentine pesos. For further discussion please see “Item 5. Operating and Financial Review and Prospects — A. Operating Results — Local Currency Exchange Rate.”

We are involved in litigation proceedings.

We are currently involved in various litigation proceedings, which could result in unfavorable decisions or financial penalties against us, and we will continue to be subject to future litigation proceedings, which could have material adverse consequences to our business.

Our financial condition or results from operations could be adversely affected if certain material claims are resolved against us. For a discussion of pending lawsuits against us see Note 34.3 to our Consolidated Financial Statements.

The values of our generation subsidiaries’ long-term energy supply contracts are subject to fluctuations in the market prices of certain commodities.

We have economic exposure to fluctuations in the market prices of certain commodities as a result of the long-term energy sales contracts we have entered into. We and our subsidiaries have material obligations as selling parties under long-term fixed-price electricity sales contracts. Prices in these contracts are indexed according to different commodities, exchange rate, inflation and the market price of electricity. For further discussion, please refer to “Item 5. Operating and Financial Review and Prospects — F. Tabular Disclosures of Contractual Obligations — Contractual Operational Obligations” and “Item 11. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

Our controlling shareholders may have conflicts of interest relating to our business.

Enel owns 92.1% of Endesa Spain, which in turn owns 60.6% of Enersis’ share capital. Our controlling shareholders have the power to determine the outcome of most material matters that require shareholders’ votes, such as the election of the majority of our board members and, subject to contractual and legal restrictions, the distribution of dividends. Our controlling shareholders also can exercise influence over our business strategy and operations. Their interests may in some cases differ from those of our other shareholders and independent directors. Enel and Endesa Spain conduct their business in South America through us as well as through entities in which we do not have an equity interest. For further information of our controlling shareholders, please refer to “Item 7. Major Shareholders and Related Party Transactions — A. Major Shareholders.”

Environmental regulations in the countries in which we operate and other factors may cause delays or impede the development of new projects, as well as may increase the costs of operations and capital expenditures.

Our operating subsidiaries are subject to environmental regulations which, among other things, require us to perform environmental impact studies for future projects and obtain permits from both local and national regulators. Approval of these environmental impact studies may take longer than originally planned, and also, may be withheld by governmental authorities. Local communities, ethnic and environmental activists, among others, may intervene during the approval process in order to delay or prevent the project’s development. They may also seek injunctive or other relief, with negative implications for us if they should succeed with their claims. For example, our HidroAysén project in Chile was submitted for approval by the environmental authorities on February 27, 2009, and received approval more than two years later, on May 9, 2011. Environmental approval for the transmission side of the project is still pending as of the date of this Report. This project is not feasible without such transmission authorization.

Environmental regulations for existing generation capacity may become stricter, thus increasing capital investments. For example, in January 2011, Decree 13 of the Ministry of the Environment in Chile defined emission standards for thermoelectric plants to be met within a term of two and a half years to five years.

In addition to environmental matters, there are other factors that may adversely affect our ability to build new facilities or to complete projects currently under development on time, including delays in obtaining regulatory approvals, shortages or increases in the price of equipment, materials or labor, strikes, adverse weather conditions, natural disasters, accidents or other unforeseen events.

Delays or modifications to any proposed project and laws or regulations may change or be interpreted in a manner that could adversely affect our operations or our plans for companies in which we hold investments. See “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework.”

Our business may be adversely affected by judicial decisions on environmental qualification resolutions for electricity projects in Chile.

The environmental qualification resolutions term for electricity generation and transmission projects in Chile have more than doubled primarily due to the judicial decisions against such projects, environmental opposition and social criticism, which cast doubt on the ability of these projects to obtain such resolutions and increase the uncertainty for investing in such projects in Chile. Such uncertainty is forcing companies to reassess their business strategies as the delay in the construction of electricity generation and transmission projects may result in a supplying problem in the next five or six years.

In August 2012, a judicial decision of the Supreme Court of Chile conclusively precluded the construction of the Castilla thermoelectric power plant (unrelated to Enersis) in the Atacama region by unanimously ruling in favor of the appeal submitted by the local communities opposing the project. The Court also revoked the environmental qualification resolutions for both the thermoelectric power plant and the port involved in the project. In addition, the Court indicated that the developer must submit a single environmental impact study for both the power plant and the port.

The Supreme Court of Chile repealed and overturned the environmental qualification resolutions because it did not adequately meet the requirements. This judgment not only affects the Castilla power plant project but also affects other complex projects involving more than one activity, such as mining projects that require construction of ports or, if taken to the extreme, power generation projects that require the construction of associated transmission lines.

Our power plant projects may encounter significant opposition from groups who may ultimately damage our reputation and could result in impairment of goodwill.

Our reputation is the foundation of our relationship with key stakeholders and other constituencies. If we are unable to effectively manage real or perceived issues, which could negatively impact sentiments toward us, our ability to operate could be impaired and our financial results could suffer.

The development of new power plants may face opposition from several stakeholders, such as ethnic groups, environmental groups, local communities and political parties, among others, all of whom may affect the company’s reputation and goodwill. For example, our HidroAysén project, whose study is being undertaken jointly together with Colbún, has encountered substantial opposition by environmental activists. Such groups are sometimes financed internationally, and may receive global attention. Likewise, settlers and fishermen have halted the construction of our Bocamina II coal-fired thermal power plant, thus postponing the project timetable. Similarly, El Quimbo hydroelectric project in Colombia has faced constant social demands which have delayed the project construction and increased its costs. The operation of our current thermal power plants may also affect our goodwill, due to emissions such as particulate matter, sulfur dioxide and nitrogen oxides, which could adversely affect the environment.

Damage to our reputation may exert considerable pressure on regulators, creditors, and other stakeholders, and ultimately lead to projects and operations which may not be optimal, as well as to lower stock prices, and failure to attract or retain valuable employees, all of which could result in an impairment of goodwill. For more information regarding our projects under development please see “Item 4. Information on the Company — D. Property, Plants and Equipment — Projects under Development.”

Our business may experience adverse consequences if we are unable to reach satisfactory collective bargaining agreements with our unionized employees.

Many of our employees are members of unions and have collective bargaining agreements which expire from time to time, and need to be renewed on a regular basis. Our business, financial condition and results of operations could be adversely affected by a failure to reach agreement with any labor union representing such employees, or by an agreement with a labor union that contains terms that are not in line with our expectations. For example, Edesur’s operating costs increased by Ch$ 10,563 million during the first half of 2011 due to higher personnel expenses as a result of wage increases under collective agreements.

Certain employees have highly specialized skills. As a consequence, certain actions by these employees, such as strikes, walk-outs or stoppages, could negatively impact our operating and financial performance, as well as our reputation. For more information on collective bargaining agreements and unionized employees please see “Item 6. Directors, Senior Management and Employees — D. Employees.”

Interruption or failure of our information technology and communications systems and external attacks or invasions of these systems could have an adverse effect on our operations and results.

We depend on Information technology, communication and processing systems (collectively, “IT systems”) to operate our businesses, the failure of which could adversely affect our financial condition and results of operations.

IT systems are all vital to our generation subsidiaries’ ability to monitor our power plants’ operations, maintain generation and network performance, adequately generate invoices to customers and stock up, achieve operating efficiencies and meet our service targets and standards. Our distribution subsidiaries could also be affected adversely since they rely heavily on IT systems to monitor their grids, billing processes to millions of clients, and customer service platforms, among others. Temporary or long-lasting operational failures of any of these IT systems could have a material adverse effect on our results of operations.

In the last few years, global cyber attacks on security systems and IT systems have intensified. We are exposed to cyber-terrorist attacks aimed at damaging our assets through computer networks, cyber-spying involving strategic information that may be beneficial for third parties, and cyber-robbery of proprietary and confidential information, including information on our clients. In early 2012, a cyber attack was organized by Anonymous Operation Green Rights to protest against our potential future construction of hydroelectric power plants in the Chilean Patagonia. More significant cyber attacks may have an adverse effect on our operations, results and image.

We rely on electricity transmission facilities that we do not own or control. If these facilities do not provide us with an adequate transmission service, we may not be able to deliver the power we sell to our final customers.

We depend on transmission facilities owned and operated by other unaffiliated power companies to deliver the electricity we sell. This dependence exposes us to several risks. If transmission is disrupted, or transmission capacity is inadequate, we may be unable to sell and deliver our electricity. If a region’s power transmission infrastructure is inadequate, our recovery of sales costs and profits

may be insufficient. If restrictive transmission price regulation is imposed, transmission companies upon whom we rely may not have sufficient incentives to invest in expansion of their transmission infrastructure, which could adversely affect our operations and financial results. On February 27, 2010, due to the 8.8 magnitude earthquake on the Richter scale in Chile, Transelec, a transmission company unrelated to us, experienced damages to its high voltage transmission line which prevented us from selling and distributing our electricity to final consumers.

On September 24, 2011, nearly 10 million people located in central Chile experienced a blackout (affecting more than half of Chile’s 17 million inhabitants), due to the failure of Transelec’s 220 kV Ancoa substation, which led to the disruption of two 500 kV transmission lines in the SIC (the Chilean Central Interconnected System), and the subsequent failure of the remote recovery computer software used by CDEC to operate the grid. This blackout, which lasted two hours, highlighted the fragility of the transmission grid and demonstrated the need to increase investments in network expansion and in technological improvements that enhance the reliability of the transmission grid.

The relative illiquidity and volatility of Chilean securities markets could adversely affect the price of our common stock and ADS.

Chilean securities markets are substantially smaller and less liquid than the major securities markets in the United States. In addition, Chilean securities markets may be affected materially by developments in other emerging markets. The low liquidity of the Chilean market may impair the ability of holders of ADS to sell shares of our common stock withdrawn from the ADS program into the Chilean market in the amount and at the price and time they wish to do so. As of the date of this Report, average trading of our ADS on the New York Stock Exchange (“NYSE”) accounts for a volume higher than the trading of the underlying stock in Chile. For further discussion please see “Item 9. The Offer and Listing — A. Offer and Listing Details — Market Price and Volume Information.”

Lawsuits against us brought outside of the South American countries in which we operate, or complaints against us based on foreign legal concepts may be unsuccessful.

All of our assets are located outside of the United States. All of our directors and all of our officers reside outside of the United States and most of their assets are located outside the United States as well. If any shareholder were to bring a lawsuit against our directors, officers or experts in the United States, it may be difficult for them to effect service of legal process within the United States upon these persons or to enforce against them, in United States or Chilean courts, judgments obtained in United States courts based upon the civil liability provisions of the federal securities laws of the United States. In addition, there is doubt as to whether an action could be brought successfully in Chile on the basis of liability based solely upon the civil liability provisions of the United States federal securities laws.

If the current preemptive rights offering is completed, our shares of common stock will not have the rights granted by former Chapter XXVI.

The Central Bank of Chile Decision 1333-01-070510 adopted on May 10, 2007 extended the effects of the former Chapter XXVI to capital increases approved after April 18, 2001. Under the former Chapter XXVI and the Foreign Investment Contracts, the Central Bank of Chile agreed to grant guaranteed access to the formal exchange market to convert Chilean pesos into U.S. dollars (see “Item 10. Additional Information. D — Exchange Rate Controls” for further detail).

As of April 19, 2001, Chapter XXVI was eliminated and new investments in ADSs or shares by non-residents of Chile are now governed instead by Chapter XIV of the Compendium. This change was made with the purpose of simplifying and facilitating the flow of capital to and from Chile. As a result of the elimination of Chapter XXVI, access to the Formal Exchange Market is no longer assured. Foreign investors who have purchased their shares under a foreign investment contract pursuant to Chapter XXVI currently (but only until the capital increase is effective and new shares are issued) continue to have guaranteed access to the Formal Exchange Market for the purpose of converting pesos to U.S. dollars and repatriating from Chile amounts received with respect to the shares of Common Stock purchased or deposited shares of Common Stock withdrawn from deposit on surrender and cancellation of ADSs (including amounts received as cash dividends and proceeds from the sale in Chile of the underlying shares of Common Stock and any rights with respect thereto).

Chapter XIV regulates the following type of investments: credits, deposits, investments and equity contributions (such as the contributions to be made to Enersis pursuant to the current shares to be issued regarding the capital increase).

As a result of the foregoing, and once the capital increase is effective, and new shares are issued, these securities (and the current Common Stock of Enersis held by non-Chilean residents or domiciles) will be subject to Chapter XIV of Central Bank of Chile’s Compendium. A Chapter XIV investor may at any time repatriate an investment made in Enersis upon sale of the shares of Enersis and the profits derived therefrom, with no monetary ceiling, subject to the then effective regulations, which must be reported to the Central Bank of Chile.

Except for compliance with tax regulations and some reporting requirements, currently there are no rules in Chile affecting repatriation rights, except that the remittance of foreign currency must be made through a Formal Exchange Market entity. However, the Central Bank of Chile has the authority to change such rules and impose exchange controls.

Enersis formally requested permission from the Central Bank of Chile to enter into a new Foreign Investment Contract to include its capital increase approved by Enersis’ shareholders’ meeting held on March 31, 2003, which was granted by the Central Bank of Chile on September 7, 2007, subject to the execution and delivery of a new Foreign Investment Contract, dated September 24, 2008. Nevertheless, the Central Bank of Chile’s approval, aimed at extending the effects of the former Chapter XXVI to the capital increase approved in March 31, 2003, is subject to the condition that Enersis informs the Central Bank of Chile with respect to the measures adopted in connection with the issuance of new shares prior to such future capital increase in order to differentiate new shares from the shares issued previously under the former Chapter XXVI and enable shareholders to obtain relevant information about such differences. If Enersis does not comply with this condition, the Central Bank of Chile could revoke its approval and the benefits granted to the shares issued in the last capital increase of Enersis by the former Chapter XXVI. It is not certain that additional Chilean restrictions applicable to the holders of ADRs, the disposition of underlying shares of common stock or the repatriation of the proceeds from such disposition will not be imposed in the future, nor can there be any assessment of the duration or impact of such restrictions if imposed.

Item 4. Information on the Company

A.	History and Development of the Company.

History

Enersis S.A. (Enersis) is a publicly held limited liability stock corporation organized under the laws of the Republic of Chile. The existence of our company under its current name dates back to August 1, 1988.


Street address:		Santa Rosa 76, Santiago, Código Postal 8330099, Chile.
Telephone:		(562) 2353-4639
Fax:		(562) 2378-4789
Web Site:		www.enersis.cl

The Company’s authorized representative in the United States of America is Puglisi & Associates, whose contact information is:


Street address:		850 Library Avenue, Suite 204, Newark, Delaware 19711
Telephone:		1(302) 738-6680

We are an electricity utility company engaged, through our subsidiaries and affiliates, in the generation, transmission and distribution of electricity businesses in Chile, Brazil, Colombia Peru and Argentina.

We are one of the largest publicly listed companies in the electricity sector in South America. We trace our origins to Compañía Chilena de Electricidad Ltda., or CCE, which was formed in 1921 as a result of the merger of Chilean Electric Tramway and Light Co., founded in 1889 and Compañía Nacional de Fuerza Eléctrica (CONAFE), with operations dating back to 1919. In 1970, the Chilean government nationalized CCE. In 1981, CCE’s operations were divided into one generation company, the current AES Gener S.A. (Gener), a currently unrelated company, and two distribution companies, one with a concession in the Valparaíso Region, the current Chilquinta S.A., a currently unrelated company, and the other with a concession in the Santiago metropolitan region, Compañía Chilena Metropolitana de Distribución Eléctrica S.A. From 1982 to 1987, the Chilean electric utility sector went through a process of re-privatization. In August 1988, Compañía Chilena Metropolitana de Distribución Eléctrica S.A. changed its name to Enersis S.A. and became the new parent company of Distribuidora Chilectra Metropolitana S.A., later renamed Chilectra S.A. In the 1990s, we diversified into electricity generation and transmission through our increasing equity stakes in Endesa Chile.

We began our international operations in 1992 with our investment in Edesur, an Argentine electricity distribution company. That same year, Endesa Chile, which at that time was not our subsidiary, also started its international operations with its investment in Endesa Costanera, an electricity generation company. We then expanded primarily into electricity generation, transmission and distribution businesses in four South American countries: Argentina, Brazil, Colombia and Peru. We remain focused on the electricity sector, although we have small operations in other businesses that represent less than 1.0% of our consolidated assets, in the aggregate.

In 2005, Endesa Brasil was formed as a company to manage all generation, transmission and distribution assets that Endesa Latinoamérica, S.A.U., or “Endesa Latinoamérica,” (a subsidiary of Endesa Spain formerly known as Endesa Internacional), Enersis, Endesa Chile and Chilectra held in Brazil; namely, through Ampla, Endesa Fortaleza, CIEN, Cachoeira Dourada and Coelce. As of December 31, 2012, Enersis directly and indirectly controlled 54.3% of Endesa Brasil’s share capital.

In order to achieve synergies in Peru, in 2006, we merged Edegel and Etevensa (60% owned by Endesa Spain), a 457 MW thermoelectric generation company.

In September 2007, we merged our generation subsidiaries in Colombia to form Emgesa. As of December 31, 2011, Enersis indirectly controlled 16.1% of Emgesa’s share capital. Pursuant to the terms of a shareholders’ agreement with Endesa Latinoamérica, we control and therefore consolidate Emgesa through Endesa Chile.

In February 2009, Codensa, our Colombian distribution subsidiary, acquired approximately 49% of DECSA, an investment vehicle, for Ch$ 23.7 billion. The remaining 51% was acquired by Empresa de Energía de Bogotá (EEB). Codensa and EEB jointly control DECSA. In March 2009, DECSA acquired 82.3% of Empresa de Energía de Cundinamarca S.A. (EEC), a formerly state-owned company that was privatized that year for Ch$ 48.5 billion. EEC is a Colombian company primarily engaged in trading of electricity in Cundinamarca Department.

Since June 2009, Enel is the ultimate controller of Enersis by virtue of its 92.1% equity interest in Endesa Spain. Endesa Spain through Endesa Latinoamérica holds 60.6% of the share capital of Enersis.

Enel is a publicly-traded company headquartered in Italy, primarily engaged in the energy sector, with a presence in 40 countries worldwide, and over 97,000 MW of net installed capacity. It provides service to more than 61 million customers through its electricity and gas businesses.

In October 2009, Endesa Chile purchased an additional 29.4% of Edegel from Generalima, a Peruvian indirect subsidiary of Endesa Spain. With this transaction, Endesa Chile increased its economic interest in Edegel from 33.1% to 62.5% and in turn, our economic interest at the Enersis level increased to 37.5%. In the same month, we acquired an additional 24.0% of the share capital of our Peruvian subsidiary, Edelnor, increasing our direct and indirect ownership stake in Edelnor from 33.5% to 57.5%.

In October, 2011, Endesa Latinoamérica purchased an additional 7.7% equity stake in the Brazilian distributor Ampla from Energias de Portugal S.A. (EDP). After the transaction, Endesa Latinoamérica has 99.6% of Ampla’s voting rights.

In March 2012, Endesa Latinoamérica announced a public offer to purchase the remaining shares representing 0.36% of the capital of Ampla and Ampla Investimentos e Serviços S.A. (“Ampla Investimentos”), from the minority shareholders. As a result of the public offer to purchase, Endesa Latinoamérica acquired 10,354,610 shares of Ampla, representing 0.0003% of its share capital and 361,569 shares of Ampla Investimentos, representing 0.003% of its share capital. The delisting of the securities of Ampla Investimentos was completed on May 25, 2012.

As of December 31, 2012, we had 15,171 MW of installed capacity with 198 power units in the five countries in which we operate, 14.0 million distribution customers covering approximately 50 million inhabitants, consolidated assets of Ch$ 13,318 billion and operating revenues of Ch$ 6,578 billion for the year then ended.

Investments, Capital Expenditures and Divestitures

We coordinate the overall financing strategy, including terms and conditions of borrowings by, and intercompany advances to, our subsidiaries to optimize debt and liquidity management. For the most part, our operating subsidiaries independently plan capital expenditure financed by internally generated funds or direct financings. One of our goals is to focus on investments that will provide long-term benefits, such as energy loss reduction projects. Additionally, by focusing on Enersis as a whole and seeking to provide services across the group of companies, we aim to reduce investments at the individual subsidiary level in items such as procurement, telecommunication and information systems. Although we have considered how these investments will be financed as part of the Company’s budget process, we have not committed to any particular financing structure, and investments will depend on the market conditions prevailing at the time the cash flows are needed.

Our investment plan is flexible enough so as to adapt to changing circumstances by giving different priorities to each project in accordance with profitability and strategic fit. Investment priorities are currently focused on developing the capacity plan in Chile and Colombia, to guarantee adequate levels of quality of supply and due concern for environmental issues.

For the 2013-2017 period, we expect to make capital expenditures of Ch$ 4,544 billion in our controlled subsidiaries, related to investments currently in progress, maintenance of our distribution network and in our other businesses, and maintenance of existing generation plants and in the studies required to develop other potential generation projects. For further detail regarding these projects, please see “Item 4. Information on the Company— D. Property, Plants and Equipment — Projects under Development.”

The table below sets forth the expected capital expenditures for the 2013-2017 period and the capital expenditures incurred by our subsidiaries in 2012, 2011 and 2010:

Capital Expenditure (1)

2013-2017

2012

2011

2010

(in million of Ch$)

Chile

1,679,186

130,813

158,656

232,562

Abroad

2,864,760

587,168

527,350

468,779

Total

4,543,946

717,981

686,006

701,341

(1)	Capex figures represent effective payments for each year except for future projections.

Capital Expenditures 2012, 2011 and 2010

Our investments in the last three years are related principally to the 350 MW Bocamina II project in Chile and the 400 MW, El Quimbo project in Colombia. Bocamina II began commercial operations in October 2012 with 350 MW of installed capacity. El Quimbo project is still in progress. In addition, we also invested to expand distribution service in response to increasing demand for energy, investments to improve quality of service and safety and investments to prevent energy losses.

Investments currently in progress

Our material plans in progress include completion of El Quimbo project, which is expected by April 2015 to add 400 MW of capacity to our Colombian operations in response to increased demand in that market; and continuation of our plans in Chile and abroad to expand distribution service and reduce energy losses to improve efficiency and profitability of our distribution operations. In general terms, projects in progress are expected to be financed with resources to be provided by external financing as well as internally generated funds for each of the companies described.

B. Business Overview.

We are a publicly held limited liability stock corporation with consolidated operations in Chile, Brazil, Colombia, Peru and Argentina. Our core business segments are electricity generation, transmission and distribution. We also participate in other activities which are not part of our core business. Since these non-core activities represent 0.4% of our 2012 revenues, we do not report them as a separate business segment for purposes of this discussion, or under IFRS.

Revenues by Business Segment


	Year ended December 31,
	2012			2011			2010			% Change 2012 vs. 2011
	(in million of Ch$)
Generation and Transmission Business Segment
Endesa Chile and Chilean subsidiaries		1,156,118			1,257,995			1,345,371			(8.1	)%
Endesa Costanera (Argentina)		295,140			341,824			507,516			(13.7	)%
El Chocón Endesa (Argentina)		49,193			48,341			295,231			1.8	%
Cachoeira Dorada (Brazil)		155,195			126,646			211,263			22.5	%
Endesa Fortaleza (Brazil)		139,186			129,485			150,371			7.5	%
CIEN (Brazil)		72,523			59,918			115,663			21.0	%
Emgesa (Colombia)		580,151			498,569			98,909			16.4	%
Edegel (Peru)		282,124			239,842			57,173			17.6	%

Less: Intercompany Transactions		(2,367	)		(2,594	)		(904	)		(8.8	)%

Total		2,727,263			2,700,026			2,780,593			1.0	%

Distribution Business Segment
Chilectra and subsidiaries (Chile)		984,738			1,046,191			1,046,387			(5.9	)%
Edesur (Argentina)		321,242			279,725			1,016,997			14.8	%
Edelnor (Peru)		385,013			329,309			940,654			16.9	%
Ampla (Brazil)		1,074,237			1,117,269			785,890			(3.9	)%
Coelce (Brazil)		806,427			859,446			307,159			(6.2	)%
Codensa (Colombia)		888,586			815,487			295,539			9.0	%

Total		4,460,243			4,447,427			4,392,626			0.3	%

Less: Consolidation Adjustments and Other Businesses		(609,839	)		(612,573	)		(609,638	)		(0.4	)%

Total		6,577,667			6,534,880			6,563,581			0.7	%

For further information related to operating revenues and total income by business segment, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 33.2 to our Consolidated Financial Statements.

Electricity Generation Business Segment

As of December 31, 2012, electricity generation represented 41% of our operating revenues and 54% of our operating income, in both cases before consolidation adjustments.

Our consolidated electricity sales for 2012 were 66,311 GWh and our production was 58,694 GWh, 3.1% and 2.3% higher than in 2011, respectively. Our total installed capacity in 2012 was 15,171 MW, 339 MW higher than in December 31, 2011, due to the addition of the second steam turbine unit (TV2) at the Bocamina II project, which has a capacity of 350 MW. This was partially offset by the reduction of installed capacity at the Santa Rosa and Ventanilla facilities by 3 MW and 8 MW, respectively.

Our electricity generation business is conducted primarily through Endesa Chile, which has consolidated operations in Chile, Colombia, Peru and Argentina. We also have consolidated operations in Brazil through Endesa Brasil.

The following tables summarize the information relating to Enersis’ electricity generation:

ENERSIS ELECTRICITY DATA PER COUNTRY


	Year ended December 31,
	2012		2011		2010
Chile
Number of generating units (1) (2)		108		107		107
Installed capacity (MW (2) ) (3)		5,961		5,611		5,611
Energy generated (GWh) (4)		20,194		20,722		20,914
Energy sales (GWh)		21,277		22,070		21,847
Argentina
Number of generating units (1)		20		20		20
Installed capacity (MW) (3)		3,652		3,652		3,652
Energy generated (GWh) (4)		11,289		10,801		10,940
Energy sales (GWh)		11,852		11,381		11,378
Brazil
Number of generating units (1)		13		13		13
Installed capacity (MW) (3)		987		987		987
Energy generated (GWh) (4)		5,177		4,155		5,095
Energy sales (GWh)		7,291		6,828		6,790
Colombia
Number of generating units (1) (2)		30		30		30
Installed capacity (MW) (2) (3)		2,914		2,914		2,914
Energy generated (GWh) (4)		13,294		12,090		11,283
Energy sales (GWh)		16,304		15,112		14,817
Peru
Number of generating units (1)		25		25		25
Installed capacity (MW) (3)		1,657		1,668		1,668
Energy generated (GWh) (4)		8,740		9,153		8,466
Energy sales (GWh)		9,587		9,450		8,598
Total
Number of generating units (1)		196		195		195
Installed capacity (MW) (3)		15,171		14,833		14,833
Energy generated (GWh) (4)		58,694		56,921		56,699
Energy sales (GWh)		66,311		64,840		63,431

(1)

For details on generation facilities, see “Item 4. Information on the Company— D. Property, Plants and Equipment — Property, Plants and Equipment of Generating Companies.” Figures differ from those previously reported, as the current figures include the number of generation units instead of generation facilities.

(2)	The San Antonio mini hydroplant in Colombia has been consolidated since May 2010; and the Bocamina II TV2 generation unit in Chile has been consolidated since April 2012.

(3)

Total installed capacity is defined as the maximum MW capacity in generation units, under specific technical conditions and characteristics, in most cases confirmed by satisfaction guarantee tests performed by equipment suppliers. Figures may differ from installed capacity declared to governmental authorities and customers in each country, according to criteria defined by such authorities and relevant contracts.

(4)	Energy generated defined as total generation minus own power plant consumption and technical energy losses.

In the electricity industry, it is common to segment the business into hydroelectric and thermoelectric generation, because each type of generation has significantly different variable costs. Thermoelectric generation requires the purchase of fuel, thereby leading to high variable costs as compared with hydro generation from reservoirs or rivers with no marginal costs. Of our total consolidated generation in 2012, 60% was from hydroelectric sources, 40% came from thermal sources, and wind energy represented less than 1%.

The following table summarizes Enersis’ consolidated generation by type of energy:

ENERSIS CONSOLIDATED GENERATION BY TYPE OF ENERGY (GWh)


	Year ended December 31,
	2012				2011				2010
	Generation		%		Generation		%		Generation		%
Hydroelectric		35,035		59.7		33,676		59.2		33,689		59.4
Thermal		23,505		40.0		23,112		40.6		22,867		40.3
Other generation (1)		153		0.3		132		0.2		143		0.3

Total generation		58,694		100.0		56,921		100.0		56,699		100.0

(1)	Other generation refers to the generation from the wind farms Canela and Canela II.

In the countries in which we operate, the potential for contracting electricity is generally related to electricity demand. Customers identified as small volume regulated customers, such as residential customers subject to government regulated electricity tariffs, must purchase electricity directly from a distribution company. These distribution companies, which purchase large amounts of electricity for small volume residential customers, generally enter into contractual agreements with generators at a regulated tariff price. Those identified as large volume industrial customers also enter into contractual agreements with energy suppliers. However, such large volume industrial customers are not subject to the regulated tariff price. Instead, these customers are allowed to negotiate the price of energy with generators based on the characteristics of the service required. Finally, the pool market, where energy is normally sold at the spot price, is not carried out through contracted pricing.

The following table contains information regarding Enersis’ consolidated sales of electricity by type of customer for each of the periods indicated:

ENERSIS CONSOLIDATED ELECTRICITY SALES BY TYPE OF CUSTOMER (GWh)


	Year ended December 31,
	2012				2011				2010
	Sales		%		Sales		%		Sales		%
Regulated customers		32,679		49.3		31,007		47.8		31,530		49.7
Unregulated customers		17,084		25.8		16,563		25.5		15,535		24.5

Total Contracted sales (1)		49,763		75.0		47,570		73.4		47,065		74.2
Electricity pool market sales		16,548		25.0		17,270		26.6		16,366		25.8

Total electricity sales		66,311		100.0		64,840		100.0		63,431		100.0

(1)	Includes sales to distribution companies not backed by contracts in Chile and Peru.

The specific energy consumption limit (measured in GWh) for regulated and unregulated customers is country specific. Moreover, regulatory frameworks often require that regulated distribution companies have contracts to support their commitments to small volume customers and also determine which customers can purchase energy in electricity pool markets.

Operations in Chile

Endesa Chile owns and operates a total of 108 generation units in Chile directly and through our subsidiaries Pehuenche, San Isidro, Celta, Endesa Eco and our jointly controlled company GasAtacama. Of these generation facilities, 38 are hydroelectric, with a total installed capacity of 3,465 MW. This represents 58.1% of our total installed capacity in Chile. There are 19 thermal units that operate with gas, coal or oil with a total installed capacity of 2,418 MW, representing 40.6% of our total installed capacity in Chile. There are 51 wind power units with 78 MW in the aggregate, representing 1.3% of our total installed capacity in Chile. All of our generation units are connected to the country’s central interconnected electricity systems, Sistema Interconectado Central (SIC), except for eight thermoelectric units (six GasAtacama and two Celta units) which are connected to the Sistema Interconectado del Norte Grande (SING) in the north.

For information on the installed generation capacity for each of the Company’s Chilean subsidiaries, see “Item 4. Information on the Company — D. Property, Plants and Equipment — Property, Plants and Equipment of Generating Companies.”

Our total electricity generation in Chile (including the SIC and the SING) accounted for 30.7% of total electricity production in Chile during 2012.

The following table sets forth the electricity generation for each of our Chilean subsidiaries:

ELECTRICITY GENERATION BY SUBSIDIARY IN CHILE (GWh)


	Year ended December 31,
	2012		2011		2010
Endesa		12,339		11,458		11,539
Pehuenche		2,625		2,983		2,970
Pangue (1)		326		1,713		1,615
San Isidro (1)		3,529		2,460		2,157
Celta		803		908		995
GasAtacama		369		1,026		1,445
Endesa Eco		204		173		192

Total		20,194		20,722		20,914

(1)	The differences in electricity generation between 2012 and 2011 is due to the fact that Pangue was merged with San Isidro on May 1, 2012 and since that date Pangue’s electricity generation is included in San Isidro.

The potential energy in Chilean reservoirs reached 2,391 GWh in 2012, a decrease of 1,454 GWh, or 38%, compared to 3,844 GWh in 2011 and 3,559 GWh in 2010.

Generation by type in Chile is shown in the following table:

ELECTRICITY GENERATION BY TYPE IN CHILE (GWh)


	Year ended December 31,
	2012				2011				2010
	Generation		%		Generation		%		Generation		%
Hydroelectric generation		11,221		55.6		11,916		57.5		12,625		60.4
Thermal generation		8,820		43.7		8,674		41.9		8,146		38.9
Other generation (1)		153		0.8		132		0.6		143		0.7

Total generation		20,194		100.0		20,722		100.0		20,914		100.0

(1)	Other generation refers to the generation of the Canela and Canela II wind farms.

Our thermal electric generation facilities are either natural gas, LNG, coal or oil-fired. In order to satisfy our natural gas and transportation requirements, we enter into long-term gas contracts with suppliers who establish maximum supply amounts and prices and long-term gas transportation agreements with the pipeline companies, which are currently Gas Andes and Electrogas (an Endesa Chile related company). Since March 2008, all of Endesa Chile’s natural gas units can operate with natural gas or diesel and since December 2009, San Isidro, San Isidro 2 and Quintero can operate with LNG.

Because of the lack of Argentine natural gas since 2006, Endesa Chile has used coal and diesel intensively, and more recently LNG has replaced our prior dependence on Argentine natural gas. Diesel consumption in 2012, 2011 and 2010 was 39,000 tons, 33,000 tons and 51,000 tons, respectively. On the other hand, coal consumption was 914,000 tons, 600,000 tons and 486,000 tons, in 2012, 2011 and 2010, respectively.

In order to ensure the coal supply to its Bocamina and Tarapacá plants, Endesa Chile contracted with Endesa Energía in 2012 to supply and transport 1,550,000 tons of coal for delivery during the period from September 2012 to December 2013.

Endesa Chile exercised its option to change its supply arrangements pursuant to the terms of the Flexible Liquefied Natural Gas Sale and Purchase Agreement with BG. By exercising this option, the reference price changed from the Brent index to the Henry Hub index and the price of LNG that BG is obligated to deliver under the contract has been reduced significantly effective January 1, 2013.

In 2012, the Quintero LNG terminal resolved to increase the terminal’s present regasification capacity by 50%. This process is expected to be completed during the first half of 2014 and will enable Endesa Chile to increase its availability of gas in case of need.

Electricity sales countrywide in Chile, including sales other than ours, increased 5.2% during 2012, with sales in the SIC increasing by 3.9% and in the SING by 5.7%, as detailed in the following table:

ELECTRICITY SALES PER SYSTEM IN CHILE (GWh)

Year ended December 31,

2012

2011

2010

Electricity sales in the SIC

46,288

43,805

41,061

Electricity sales in the SING

14,831

14,272

13,792

Total electricity sales

61,118

58,078

54,854

Our electricity sales in Chile reached 21,277 GWh in 2012 and 22,070 GWh in 2011, which represent a 34.8% and 38.0% market share, respectively. The percentage of the energy purchases to satisfy our contractual obligations to third parties has slightly decreased from 7.9% in 2011 to 7.8% in 2012 as a result of the slight increase in our generation.

The following table sets forth our electricity generation and purchases in Chile:

ELECTRICITY GENERATION AND PURCHASES IN CHILE (GWh)

Year ended December 31,

2012

2011

2010

(GWh)

%
of Volume

(GWh)

%
of Volume

(GWh)

%
of Volume

Electricity generation

20,194

92.2

20,722

92.1

20,914

94.0

Electricity purchases

1,719

7.8

1,777

7.9

1,344

6.0

Total (1)

21,913

100.0

22,498

100.0

22,257

100.0

(1)	Electricity generation plus electricity purchases differ from electricity sales due to transmission losses, as power plant consumption and technical energy losses have already been deducted.

We supply electricity to the major regulated electricity distribution companies, large unregulated industrial firms (primarily in the mining, pulp and steel sectors) and the pool market. Commercial relationships with our customers are usually governed by contracts. Supply contracts with distribution companies must be auctioned, are generally standardized and have an average term of ten years.

Supply contracts with unregulated customers (large industrial customers) are specific to the needs of each client and the conditions are agreed between both parties, reflecting competitive market conditions.

In 2012, 2011 and 2010, Endesa Chile (including GasAtacama) had 58, 54 and 59 customers, respectively. In 2012, our customers included 25 distribution companies in the SIC, 30 unregulated customers and three minor commercial customers.

The following table sets forth information regarding our sales of electricity in Chile by type of customer:

ELECTRICITY SALES PER CUSTOMER SEGMENT IN CHILE (GWh)


	Year ended December 31,
	2012				2011				2010
	Sales		% of Sales Volume		Sales		% of Sales Volume		Sales		% of Sales Volume
Regulated customers		13,971		65.7		13,481		61.1		13,840		63.3
Unregulated customers		6,334		29.8		6,772		30.7		6,456		29.6

Total Contract sales		20,306		95.4		20,252		91.8		20,296		92.9
Electricity pool market sales		971		4.6		1,817		8.2		1,551		7.1

Total electricity sales		21,277		100.0		22,070		100.0		21,847		100.0

Our most significant supply contracts with regulated customers are with our subsidiary Chilectra S.A. (Chilectra) and with Compañía General de Electricidad S.A. (CGE), an unrelated company, which are the two largest distribution companies in Chile in terms of sales.

The following table sets forth Endesa Chile’s public contracts with electricity distribution companies in the SIC for their regulated customers:


	Years (amounts in GWh)
Company	2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		2025		2026		2027
Chilectra		5,600		6,950		6,950		6,950		6,950		6,950		6,950		6,950		5,900		4,200		2,850		2,850		2,850		1,350		1,350
CGE		4,447		4,247		4,277		4,277		4,277		4,277		4,277		3,400		3,400		2,000		2,000		2,000		—		—		—
Chilquinta		1,329		1,329		1,629		1,629		1,629		1,629		1,629		1,629		1,629		1,629		1,629		969		350		350		—
Saesa		2,204		2,424		1,500		1,500		1,500		1,500		1,500		—		—		—		—		—		—		—		—

Total Endesa Chile		13,579		15,029		14,355		14,355		14,355		14,355		14,355		11,979		10,929		7,829		6,479		5,819		3,200		1,700		1,350

For 2012, 2011 and 2010, Endesa Chile and its Chilean subsidiaries hold the 46%, 45% and 46% respectively of the total publicly tendered supply regulated contracts with the distribution companies in the SIC for their regulated customers. The rest of the contracts are distributed among eight companies.

Our generation contracts with unregulated customers are generally on a long-term basis, and typically range from five to fifteen years. Such contracts are usually automatically extended at the end of the applicable term, unless terminated by either party upon prior notice. Some of them include a price adjustment mechanism in the case of high marginal costs, which also reduces the hydrological risk. Contracts with unregulated customers may also include specifications regarding power sources and equipment, which may be provided at special rates, as well as provisions for technical assistance to the customer. We have not experienced any supply interruptions under our contracts. In case we experience a force majeure event, as contractually defined, we are allowed to reject purchases and we are not required to supply electricity to our unregulated customers. Disputes are typically subject to binding arbitration between the parties, subject to limited exceptions.

The following table sets forth our sales by volume to our five largest distribution and unregulated customers in Chile for each of the periods indicated:

MAIN CUSTOMERS IN CHILE (GWh)


	Year ended December 31,
	2012				2011				2010
	Sales		% of total Sales		Sales		% of total Sales		Sales		% of total Sales
Distribution companies:
Chilectra		5,008		23.5		4,679		21.2		5,929		27.1
CGE		4,152		19.5		3,887		17.6		3,541		16.2
Chilquinta		1,407		6.6		1,332		6.0		895		4.1
Saesa Group (1)		1,312		6.2		1,066		4.8		1,061		4.9
Emel Group (2)		968		4.5		1,802		8.2		1,816		8.3

Total sales to the largest distribution companies		12,848		60.4		12,765		57.8		13,242		60.6

Unregulated customers:
Cía. Minera Los Pelambres		1,165		5.5		1,155		5.2		1,113		5.1
Cía. Minera Collahuasi (3)		1,077		5.1		1,093		5.0		1,114		5.1
Grupo CAP-CMP (4)		1,027		4.8		1,076		4.9		918		4.2
CMPC		584		2.7		683		3.1		773		3.5
Codelco		538		2.5		557		2.5		545		2.5
Cía. Minera Escondida (5)		0		0		563		2.6		638		2.9

Total sales to the largest unregulated customers		4,391		20.6		5,127		23.2		5,101		23.3

(1)	The values of the Saesa Group include the consumption of the distributors Saesa and Empresa Eléctrica de la Frontera S.A.

(2)

The values of the Emel Group for 2011 and 2012 include 50% of the supply contracts of the distributors Empresa Eléctrica de Arica S.A. (Emelari), Empresa Eléctrica de Iquique S.A. (Eliqsa) and Empresa Eléctrica de Antofagasta (Elecda), customers of GasAtacama which contracts ended in December 2011; and the consumption of Empresa Eléctrica de Melipilla, Colchagua y Maule (Emelectric), Empresa Eléctrica de Talca (Emetal) and Empresa Eléctrica de Atacama (Emelat), customers of Endesa Chile. The Emel Group is a subsidiary of the CGE Group.

(3)	Consumption of Cía. Minera Collahuasi includes the 50% of the contract of GasAtacama with this customer and the contracts with Celta.

(4)	Consumption of Grupo CAP-Compañía Minera del Pacífico S.A. (CMP) includes the contracts with CAP Huachipato, CMP Algarrobo, CMP Hierro Atacama, CMP Los Colorados, CMP Pellets and CMP Romeral.

(5)	The contract between GasAtacama and Cía Minera Escondida ended in January 2012.

We compete in the SIC primarily with two generation companies, Gener and Colbún S.A. (Colbún). According to the CDEC-SIC in 2012, Gener and its subsidiaries in the SIC had an installed capacity of 2,344 MW, of which 86.9% was thermoelectric, and Colbún had an installed capacity of 2,957 MW, of which 57.4% was thermoelectric. In addition to these two large competitors, there are a number of smaller entities with an aggregate installed capacity of 2,917 MW that generate electricity in the SIC.

Our primary competitors in the SING are E-CL (GDF Suez Group) and Gener, which have 2,135 MW and 1,465 MW of installed capacity, respectively. Our direct participation in the SING includes our 182 MW Tarapacá thermal plant, owned by our subsidiary Celta, and our participation through our jointly controlled company, GasAtacama, with 781 MW of installed capacity. In this Report, the convention is to refer to our capacity of 390 MW (50% of the actual amount) in connection with GasAtacama in proportion to Endesa Chile’s 50% stake. See “Item 4. Information on the Company— C. Organizational Structure” for details on related companies.

Electricity generation companies compete largely on the basis of price, technical experience and reliability. In addition, because 58.1% of our installed capacity in the SIC comes from hydroelectric power plants, we have lower marginal production costs than companies generating electricity through thermal plants. Our thermal installed capacity benefits from access to gas from the Quintero LNG terminal. During periods of extended droughts, however, we may be forced to buy more expensive electricity from thermoelectric generators at spot prices in order to satisfy our contractual obligations.

Directly and through our subsidiaries Pehuenche, San Isidro and Endesa Eco, we are the principal generation operator in the SIC, with 39.6% of the total installed capacity and 43.0% of the electricity sales of this system in 2012.

In the SING, our subsidiary Celta, and our jointly controlled company GasAtacama, accounted for 12.4% of the total installed capacity in 2012. Celta, our subsidiary, has a 182 MW thermal power plant connected to the SING which represents 4.0% of the total capacity of the SING. For Endesa Chile, GasAtacama represents a total of 390 MW or 8.5% of the total capacity in the SING. For further information regarding our generation capacity in Chile as of December 31, 2012, please see “Item 4. Information on the Company— D. Property, Plants and Equipment —Property, Plants and Equipment of Generating Companies.”

Operations in Argentina

We participate in electricity generation in Argentina through our subsidiaries Endesa Costanera and El Chocón, with a total of twenty power units. El Chocón owns nine hydroelectric units, with total installed capacity of 1,328 MW and Endesa Costanera owns eleven thermal units, with a total installed capacity of 2,324 MW. Our hydro and thermal generation units in Argentina represented 11.7% of the Sistema Interconectado Nacional (the Argentine NIS) installed capacity in 2012.

Our Argentine subsidiaries participate in three new companies, Manuel Belgrano, San Martín and Central Vuelta de Obligado S.A. These companies were formed to undertake the construction of three new generation facilities for FONINVEMEM. The first two plants started operations using gas turbines in 2008, with 1,125 MW of aggregate capacity, and combined cycles as of March 2010, with an additional 572 MW. The total aggregate capacity of these units is 1,697 MW (848 MW for Manuel Belgrano and 849 MW for San Martín). We expect that the third plant will start open cycle operations in mid 2013 with an installed capacity of 550 MW, and in combined cycle in mid-2015 with a total installed capacity of 800 MW.

Since 2002, government intervention and energy industry authority actions, including limiting the spot price of electricity by considering the variable cost of generating electricity with natural gas and without considering the hydrological conditions of rivers and reservoirs or the use of more expensive fuels, have led to the lack of investment in the electric power sector. (See “Item 4. Information on the Company— B. Business Overview— Electricity Industry Regulatory Framework” for further detail). In addition, from 2002, the Argentine Government has taken an active role in controlling the supply of the fuel to the electricity generation sector.

As of December 31, 2012, Endesa Costanera’s installed capacity accounted for 7.5% of the total installed capacity in the Argentine NIS. Endesa Costanera’s second combined-cycle plant can operate with either natural gas or diesel. Our 1,138 MW steam turbine power plant also can operate with either natural gas or fuel oil.

El Chocón accounted for 4.3% of the installed capacity in the Argentine NIS as of December 31, 2012. El Chocón has a 30-year concession, ending in 2023, for two hydroelectric generation facilities with an aggregate of 1,328 MW of installed capacity. The larger of the two facilities for which El Chocón has a concession of 1,200 MW of installed capacity is the primary flood control installation on the Limay River. The facility’s large reservoir, Ezequiel Ramos Mejía, enables El Chocón to be one of the Argentine NIS major peak suppliers. Variations in El Chocón’s water discharge are moderated by El Chocón’s Arroyito facility, a downstream dam with 128 MW of installed capacity. In November 2008, we finished construction work on the Arroyito dam, and increased the elevation of the reservoir water level, that allows releasing water at an additional 1,150 m3/sec, for a total of 3,750 m3/sec. The additional energy (69 GWh/year) was sold on the spot market until April 2009 and under “Energy Plus” program thereafter. Energy Plus program is the offer of new electricity capacity to supply the electricity demand growth, on top of the demand level for electricity in 2005. (For details on Energy Plus, see “Item 4. Information on the Company — B. Business Overview— Electricity Industry Regulatory Framework — Argentina”).

For information on the installed generation capacity for each of the Company’s Argentine subsidiaries, see “Item 4. Information on the Company — D. Property, Plants and Equipment—Property, Plants and Equipment of Generating Companies.”

Our total generation in Argentina reached 11,289 GWh in 2012. Our generation market share was approximately 9.0% of total electricity production in Argentina during 2012.

Hydroelectric generation in Argentina accounted for nearly 24.8% of our total generation in 2012. This was due to the restrictions of the operation of El Chocón that were imposed by CAMMESA and the drought conditions presented during the year in the Limay River and in the Collón Curá River, the main tributaries of El Chocón. Due to the drought in 2012, the region received around 65% of historic average rainfall.

Generation by type and subsidiary is shown in the following table:

ELECTRICITY GENERATION IN ARGENTINA (GWh) (1)


	Year ended December 31,
	2012				2011				2010
	Generation		%		Generation		%		Generation		%
Hydroelectric generation (El Chocón)		2,801		24.8		2,404		22.3		2,975		27.2
Thermal generation (Endesa Costanera)		8,488		75.2		8,397		77.7		7,965		72.8

Total generation		11,289		100.0		10,801		100.0		10,940		100.0

(1)	Generation minus our power plant own consumption of electricity and technical losses.

The following table sets forth our electricity generation and purchases in Argentina:

ELECTRICITY GENERATION AND PURCHASES IN ARGENTINA (GWh)


	2012				2011				2010
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		11,289		94.6		10,801		94.2		10,940		95.5
Electricity purchases		645		5.4		668		5.8		517		4.5

Total (1)		11,934		100.0		11,469		100.0		11,457		100.0

(1)	Energy generation plus energy purchases differ from electricity sales due to power plant own consumption of electricity.

The distribution of electricity sales in Argentina, in terms of customer segment and per subsidiary, is shown in the following tables:

ELECTRICITY SALES PER CUSTOMER SEGMENT IN ARGENTINA (GWh)

Year Ended December 31,

2012

2011

2010

Sales

% of
Sales
Volume

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Contracted sales

2,155

18.2

2,145

18.8

2,142

18.8

Non-contracted sales

9,696

81.8

9,236

81.2

9,236

81.2

Total electricity sales

11,852

100.0

11,381

100.0

11,378

100.0

ELECTRICITY SALES PER SUBSIDIARY IN ARGENTINA (GWh)

Year Ended December 31,

2012

2011

2010

Endesa Costanera

8,655

8,493

8,018

El Chocón

3,197

2,888

3,361

Total

11,852

11,381

11,378

During 2012, Endesa Costanera served an average of 79 unregulated customers. Endesa Costanera has no contract with distribution companies. Given the regulatory measures adopted since 2003, the current Argentine electricity industry price scenario makes sales to distribution companies less attractive than sales to the wholesale market.

The following table sets forth Endesa Costanera’s sales to its largest unregulated customers for each of the periods indicated:

ENDESA COSTANERA’S MAIN CUSTOMERS (GWh)


	Year ended December 31,
	2012				2011				2010
	Contracted Sales		% of Contracted Sales		Contracted Sales		% of Contracted Sales		Contracted Sales		% of Contracted Sales
YPF (Cemsa) (1)		145		17.1		152		20.6		188		25.7
Cencosud (Cemsa) (1)		78		9.2		73		9.9		70		9.6
Transclor (Cemsa) (1)		67		8.0		61		8.3		60		8.2
Peugeot (Cemsa) (1)		42		5.0		31		4.2		59		8.0
Rasic Hnos.		41		4.8		39		5.3		39		5.3
Hipermercado Libertad		23		2.7		—		—		—		—
Solvay		—		—		23		3.1		22		3.1

Total sales to our largest unregulated customers		395		46.8		379		51.4		438		59.9

(1)	These clients do not have contracts with Endesa Costanera, but are served through Cemsa, our affiliate.

Sales to the pool market amounted to 7,810 GWh in 2012.

During 2012, El Chocón served an average of 15 unregulated customers. El Chocón has no contract with distribution companies. The following table sets forth sales by volume to El Chocón’s largest unregulated customers for each of the periods indicated:

EL CHOCON’S MAIN CUSTOMERS (GWh)


	Year ended December 31,
	2012				2011				2010
	Contracted Sales		% of Contracted Sales		Contracted Sales		% of Contracted Sales		Contracted Sales		% of Contracted Sale
Minera Alumbrera		499		38.1		500		35.5		505		35.8
Air Liquide		161		12.3		161		11.4		131		9.3
Profertil (Cemsa) (1)		105		8.0		113		8.0		112		7.9
Praxair		98		7.5		91		6.4		87		6.2
Chevron		87		6.6		83		5.9		91		6.4
Acindar (Cemsa) (1)		81		6.2		80		5.7		80		5.7

Total sales to our largest unregulated customers		1,031		78.6		1,028		72.9		1,006		71.3

(1)	Profertil and Acindar do not have contracts with El Chocón, but are served through Cemsa, Enersis’ affiliate.

El Chocón does not have the right to terminate the operating agreement with Endesa Chile unless Endesa Chile fails to perform its obligations under the agreement. Under the terms of the operating agreement, Endesa Chile is entitled to a fee payable in U.S. dollars based on El Chocón’s annual gross revenues, payable in monthly installments. The management fee for 2012, 2011 and 2010 was US$ 2.1 million, US$ 2.1 million and US$ 2.3 million, respectively.

Electricity demand in the Argentine NIS increased 4.2% during 2012. Total electricity demand was 121,311 GWh in 2012, 116,418 GWh in 2011 and 110,767 GWh in 2010. Our Argentine subsidiaries compete with all the major power plants connected to the Argentine NIS. According to the installed capacity reported by CAMMESA in the monthly report for December 2012, our major competitors in Argentina are the state-controlled company Enarsa (with an installed capacity of 2,077 MW), nuclear units -NASA- (1,005 MW) and the binational hydroelectric units Yacyretá and Salto Grande (3,690 MW in total). The main private competitors are: AES Group, Sociedad Argentina de Energía S.A. (Sadesa), and Pampa Energía. The AES Group has eight power plants connected to the Argentine NIS with a total capacity of 3,169 MW (38% of which is hydro). Sadesa owns a total of approximately 3,731 MW, the most important of which are Piedra del Águila (hydro, 1,400 MW) and Central Puerto (thermal, 1,777 MW), while Pampa Energía, with 2,184 GWh, competes with us with six power plants, Diamante and Nihuiles (hydro, 630 MW in total), and Güemes, Loma de la Lata, Piedra Buena and Piquirenda (thermal 1,554 MW in total).

Generation in Brazil

Endesa Brasil consolidates operations of Endesa Fortaleza and Cachoeira Dourada, two generation companies; CIEN, which transmits electricity from two transmission lines between Argentina and Brazil; CTM and TESA, subsidiaries of CIEN, which are owners of the Argentine side of the lines; Ampla, the second largest electricity distribution company in the State of Rio de Janeiro; and Coelce, which is the sole electricity distributor in the State of Ceará.

As of December 2012, we had a total installed capacity of 987 MW in Brazil. Of this amount, 665 MW corresponds to Cachoeira Dourada and 322 MW to Endesa Fortaleza.

For information on the installed generation capacity for each of the Company’s Brazilian subsidiaries, see “Item 4. Information on the Company — D. Property, Plants and Equipment — Property, Plants and Equipment of Generating Companies.”

Generation by type and subsidiary in Brazil is shown in the following table:

ELECTRICITY GENERATION IN BRAZIL (GWh)


	Year ended December 31,
	2012				2011				2010
	Generation		%		Generation		%		Generation		%
Hydroelectric generation (Cachoeira Dourada)		3,722		71.9		3,121		75.1		3,430		67.3
Thermal generation (Endesa Fortaleza)		1,454		28.1		1,033		24.9		1,665		32.7

Total		5,177		100.0		4,155		100.0		5,095		100.0

The following table sets forth our electricity generation and purchases in Brazil:

ELECTRICITY GENERATION AND PURCHASES IN BRAZIL (GWh)


	Year ended December 31,
	2012				2011				2010
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		5,177		71.1		4,155		60.6		5,095		74.5
Electricity purchases		2,108		28.9		2,699		39.4		1,746		25.5

Total (1)		7,285		100.0		6,854		100.0		6,841		100.0

(1) Electricity generation and electricity purchases differ from electricity sales because of transmission losses, our power plant own consumption and technical losses have already been deducted.

Cachoeira Dourada is a hydroelectric company with ten generation units with a total installed capacity of 665 MW located in southern Brazil. It has long-term contracts with 34 distribution companies due to the bids carried out for regulated consumers by the Contratos de Comercialização de Energia no Ambiente Regulado (CCEAR). The contract sales with regulated clients were for 1,126 GWh. Additionally, during 2012, Cachoeira had medium-term contracts with 20 unregulated clients with an average duration of three years and short term contracts with 24 unregulated clients. Cachoeira’s sales to unregulated clients were 2,675 GWh.

The following table sets forth certain statistical information regarding Cachoeira Dourada’s electricity sales:

CACHOEIRA DOURADA’S ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

Year ended December 31,

2012

2011

2010

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Contracted sales

3,801

87.5

3,307

83.0

3,440

89.8

Non-contracted sales

544

12.5

679

17.0

392

10.2

Total electricity sales

4,344

100.0

3,986

100.0

3,833

100.0

Endesa Fortaleza is wholly-owned by Endesa Brasil. Endesa Fortaleza owns a combined-cycle plant with three generation units which use natural gas. The plant is located 50 kilometers from the capital of the Brazilian state of Ceará, and it began commercial operations in 2003. Since January 2010 Endesa Fortaleza has received natural gas from the Pecem regasification terminal.

Endesa Fortaleza’s market share is 0.3% of the total installed capacity of the Brazilian system and 1.0% of the thermoelectric generators. Fortaleza has a long-term contract with Coelce which expires in 2023.

The following table sets forth certain statistical information regarding Endesa Fortaleza’s electricity sales:

ENDESA FORTALEZA’S ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

Year ended December 31,

2012

2011

2010

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Contracted sales

2,690

91.3

2,690

94.7

2,690

91.0

Non-contracted sales

257

8.7

152

5.3

267

9.0

Total electricity sales

2,947

100.0

2,842

100.0

2,957

100.0

Operations in Colombia

Our generation operations in Colombia are carried out through Emgesa. We hold a 16.1% stake in Emgesa as of December 31, 2012, which we control and consolidate through Endesa Chile pursuant to a shareholder’s agreement with an Endesa Spain subsidiary who owns 21.6%.

As of December 31, 2012, our Colombian subsidiary operated 30 generation units in Colombia, with a total installed capacity of 2,914 MW. Emgesa has 2,471 MW in hydroelectric plants and 444 MW in thermoelectric plants. Our hydroelectric and thermal generation plants in Colombia represent 20.2% of the country’s total electricity generation capacity as of December 2012.

For information on the installed generation capacity for each of the Company’s Colombian subsidiaries, see “Item 4. Information on the Company — D. Property, Plants and Equipment — Property, Plants and Equipment of Generating Companies.”

Approximately 85% of our installed capacity in Colombia is hydroelectric. As a result, our electricity generation depends on the reservoir levels and rainfalls. Our generation market share in Colombia was 22.2% in 2012, 20.6% in 2011 and 19.8% in 2010. In addition to hydrological conditions, the amount of generation depends on our commercial strategy. Companies are free to offer their electricity at prices driven by market conditions and are dispatched by a centralized operating entity to generate according to the prices offered, as opposed to being dispatched according to the operating costs, as in other countries in which we operate.

During 2012, thermal generation represented 4.5% of total generation and hydroelectric generation represented the remaining 95.5% of our generation in Colombia. During 2012, hydrological conditions were normal in Colombia with rainfall around 104% of the historical average. For Emgesa, the flows in the Guavio River Basin were 106% of average and the flows in the Magdalena River (Betania) were 101% of average while the flows in the Bogotá River (Cadena Nueva) were a more favorable 146% of average.

Generation by type in Colombia is shown in the following table:

ELECTRICITY GENERATION IN COLOMBIA (GWh) (1)


	Year ended December 31,
	2012				2011				2010
	Generation		%		Generation		%		Generation		%
Hydroelectric generation		12,692		95.5		11,620		96.1		10,253		90.9
Thermal generation		602		4.5		470		3.9		1,030		9.1

Total generation		13,294		100.0		12,090		100.0		11,283		100.0

(1)	Generation minus our power plant own consumption of electricity and technical losses.

In 2012, Emgesa entered into new fuel supply contracts for the coal-fired plants in Colombia in order to increase the number of suppliers, reduce the volumes contracts and increase the coal supply for Termozipa.

The local coal price continues to be below the export coal price as high transport costs make it impossible for domestic coal to compete in the export market.

In order to secure the reliable supply of the fuel for the Cartagena plant, Emgesa entered into a fuel-oil supply contract with Petromil for a term which lasts until November 2014. A completely variable supply contract was also signed with Biomax in order to import liquid fuels should there be local supply problems. The contract with Petromil was recently extended to November 2016.

The following table sets forth our electricity generation and purchases in Colombia:

ELECTRICITY GENERATION AND PURCHASES IN COLOMBIA (GWh)


	Year ended December 31,
	2012				2011				2010
	GWh		%		GWh		%		GWh		%
Electricity generation		13,294		80.8		12,090		79.3		11,283		75.4
Electricity purchases		3,153		19.2		3,163		20.7		3,678		24.6

Total (1)		16,447		100.0		15,254		100.0		14,961		100.0

(1) Electricity generation and electricity purchases differ from electricity sales because of transmission losses, our power plant own consumption of electricity and technical losses have already been deducted.

The only interconnected electricity system in Colombia is the Sistema Interconectado Nacional (the “Colombian NIS.”) Electricity demand in the Colombian NIS increased 3.8% during 2012. Total electricity consumption was: 59,350 GWh in 2012, 57,150 GWh in 2011 and 56,148 GWh in 2010.

The generation in Colombia’s electricity market has been affected by the agreement on International Energy Transactions governing the interconnection with Ecuador’s electricity system, which began operations in 2003. During 2012, electricity sales to Ecuador were 236 GWh. Energy imports from Ecuador to Colombia were 7 GWh in 2012.

In addition, Colombia has some interconnection links with Venezuela which operate under exceptional circumstances as required by either of the two countries. In early April 2011, Colombia and Venezuela signed an agreement to supply energy to Venezuela as part of the normalization of commercial relations. The agreement also includes the import of gasoline and diesel from Venezuela. The total energy exported was 478 GWh in 2012.

The distribution of our electricity sales in Colombia, in terms of customer segment, is shown in the following table:

ELECTRICITY SALES PER CUSTOMER SEGMENT IN COLOMBIA (GWh)

Year ended December 31,

2012

2011

2010

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Contracted sales

11,719

71.9

10,544

69.8

10,946

73.9

Non-contracted sales

4,585

28.1

4,568

30.2

3,871

26.1

Total electricity sales

16,304

100.0

15,112

100.0

14,817

100.0

During 2012, Emgesa served an average of 799 contracts with 446 unregulated customers and 44 contracts with 15 distribution and trading companies. Emgesa’s sales to our distribution company, Codensa, accounted for 42.8% of our total contracted sales in 2012. Electricity sales to the five largest unregulated customers represented 5.5% of total contracted sales.

The following table sets forth our sales by volume to our largest distribution customers in Colombia for the last three years:

MAIN DISTRIBUTION AND TRADING CUSTOMERS IN COLOMBIA (GWh)


	Year ended December 31,
	2012				2011				2010
	Contracted Sales		% of contracted Sales		Contracted Sales		% of contracted Sales		Contracted Sales		% of contracted Sales
Codensa (Enersis)		5,016		42.8		5,035		47.8		4,296		39.2
Empresas Públicas de Medellín (EPM)		806		6.9		760		7.2		1,716		15.7
Centrales Eléctricas del Norte de Santander (CENS)		573		4.9		152		1.4		342		3.1
Electrificadora de Santander		373		3.2		47		0.4		72		0.7
Electrificadora del Caribe (Electrocaribe)		371		3.2		360		3.4		352		3.2
Empresa de Energía de Cundinamarca (EEC)		235		2.0		266		2.5		84		0.8
Electrificadora del Huila						416		3.9		236		2.2
Electrificadora del Meta (Meta)						82		0.8		175		1.6
Electrificadora de la Costa (Electrocosta)						—		—		555		5.1
Cía. Energética del Tolima (Enertolima)						—		—		501		4.6

Total sales to our largest distribution customers		7,375		62.9		7,118		67.4		8,329		76.2

Our most important competitors in Colombia include the following state-owned companies: Empresas Públicas de Medellín (with an installed capacity of 3,156 MW) and Isagen (with an installed capacity of 2,102 MW). We also compete with the following private sector companies in Colombia: Chivor (1,000 MW), which is owned by Gener; Colinversiones, with an installed capacity of 1,989 MW, which includes Termoflores and Epsa; and Gecelca with an installed capacity of 1,207 MW.

Operations in Peru

Through our subsidiary Edegel, we operate a total of 25 generation units in Peru, with a total installed capacity of 1,657 MW, as of December 2012. Edegel owns 18 hydroelectric units, with a total installed capacity of 746 MW. The company has seven thermal units, which represent the remaining 911 MW of total installed capacity. Our hydroelectric and thermal generation plants in Peru represent 23.3% of the country’s total electricity generation capacity according to the information reported in December 2012 by the Organismo Supervisor de la Inversión en Energía y Minería, the Supervisory Entity of the Investment on Energy and Mining (“Osinergmin”).

For information on the installed generation capacity for each of the Company’s power plants in Peru, see “Item 4. Information on the Company—D. Property, Plants and Equipment—Property, Plants and Equipment of Generating Companies.”

Generation by type in Peru is shown in the following table:

ELECTRICITY GENERATION IN PERU (GWh) (1)


	Year ended December 31,
	2012				2011				2010
	Generation		%		Generation		%		Generation		%
Hydroelectric generation		4,599		52.6		4,615		50.4		4,405		52.0
Thermal generation		4,141		47.4		4,538		49.6		4,061		48.0

Total generation		8,740		100.0		9,153		100.0		8,466		100.0

(1)

Generation minus our power plant own consumption of electricity and technical losses.

In 2012, we generated 23.4% of total electricity production in Peru.

Hydrological generation represented 52.6% of Edegel’s total production in 2012. For Edegel all hydrological contributions were above their historical average in 2012: in the Rimac River Basin (Huinco, Matucana, Callahuanca, Moyopampa, Huampaní) hydrological contributions were 124%; in the Tulumayo River (Yanango) hydrological contributions were 119%; and in the Tarma River (Chimay) hydrological contributions were 113%.

The portion of electricity supplied by Edegel’s own generation was 89.6% of total electricity sales, requiring 10.4% of purchases to satisfy contractual obligations to customers.

Edegel has gas supply, transportation and distribution contracts for its Ventanilla and Santa Rosa facilities. During 2007, the gas pipeline Camisea-Lima, owned by Transportadora del Gas del Perú S.A. (TGP), reached its full capacity. However, in May 2008, TGP started implementing restrictions on the transfer of gas through the pipeline. In order to guarantee the transportation capacity for its natural gas demand, Edegel modified its agreements during 2007 and 2008, shifting from interruptible to firm mode, with a capacity of 1.5 million m³/day (from August 2008 to July 2009) and 2.7 million m³/day (from August 2009 to July 2019). Going forward, Edegel expects that it will count on sufficient natural gas capacity for the combined cycle Ventanilla plant and part of Santa Rosa. In addition, in 2009 Edegel extended the contract for transportation and distribution from August 2019 to 2025 at a level of 2.1 million m³/day.

In August 2010, TGP awarded 0.5 million m3/d in firm transport capacity to Edegel from August 2010 until the end of 2019, in the TGP 14th open season.

The following table sets forth our electricity generation and purchases in Peru:

ELECTRICITY GENERATION AND PURCHASES IN PERU (GWh) (1)


	Year ended December 31,
	2012				2011				2010
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		8,740		89.6		9,153		95.1		8,466		96.5
Electricity purchases		1,018		10.4		469		4.9		305		3.5

Total(1)		9,758		100.0		9,622		100.0		8,771		100.0

(1)	Electricity generation plus electricity purchases differ from electricity sales because of transmission losses, our power plant own consumption of electricity and technical losses have already been deducted.

The Sistema Eléctrico Interconectado Nacional (SEIN) is the only interconnected system in Peru. Electricity sales in the SEIN increased 5.9% during 2012 compared to 2011, reaching total annual sales of 33,636 GWh.

The distribution of Edegel’s electricity sales, in terms of customer segment, is shown in the following table:

ELECTRICITY SALES PER CUSTOMER SEGMENT IN PERU (GWh)

Year ended December 31,

2012

2011

2010

Sales
(GWh)

% of Sales
Volume

Sales
(GWh)

% of Sales
Volume

Sales
(GWh)

% of Sales
Volume

Contracted sales (1)

9,092

94.8

8,632

91.3

7,550

87.8

Non-contracted sales

495

5.2

818

8.7

1,049

12.2

Total electricity sales

9,587

100.0

9,450

100.0

8,598

100.0

(1)	Includes sales to distributors without contracts.

Edegel’s electricity sales in 2012 increased 1.5% compared with 2011. Sales in the spot market decreased 39.4% due to the increase in contracted sales. During 2012, Edegel had seven regulated customers. Edegel has had contracts since 1997 with the distribution companies Luz del Sur and the Enersis’ subsidiary Edelnor. Edegel also won the bids launched by other distributors during 2006 and 2007. Edegel has thirteen unregulated customers. Sales to unregulated customers represented 30.1% of Edegel’s total contracted sales in 2012.

During 2011, only one long-term tender was called in Peru by the distributor Luz del Sur. The distributors participating in the process were Luz del Sur, Edelnor and Edecañete. The period tendered was 2018-2027, with an energy requirement of approximately 2,500 GWh/year. An amount of 2,245 GWh was granted to Cerro del Águila, Celepsa, Egesur, Enersur and Fenix. The remaining unallocated amount of 255 GWh was declared void.

During 2012, only one long-term tender was called in Peru by the distributor Edelnor. The period tendered was 2016-2027, with an energy requirement of approximately 990 GWh/year. The contracts were granted to Eepsa (12.5%), Egejunin (1.8%), Edegel (42.3%), Fenix (24.9%), and Kallpa (18.5%).

The following table sets forth our sales by volume to our largest customers in Peru for each of the periods indicated:

MAIN CUSTOMERS IN PERU (GWh)


	Year ended December 31,
	2012				2010				2011
	Contracted Sales		% of Contracted Sales		Contracted Sales		% of Contracted Sales		Contracted Sales		% of Contracted Sales
Distribution companies:
Edelnor (Regulated) (1) (2)		3,130		34.4		4,173		48.3		4,072		53.9
Luz del Sur (Regulated) (1)		1,917		21.1		1,539		17.8		917		12.1
Hidrandina (3)		573		6.3		0		0		0		0
ElectroSur (3)		362		4.0		0		0		0		0

Total sales to our largest distribution companies		5,981		65.8		5,711		66.2		4,989		66.0


Unregulated customers:
Refinería Cajamarquilla		1,332		14.6		1,320		15.3		974		12.9
Antamina		889		9.8		708		8.2		668		8.9
Siderúrgica del Perú		309		3.4		288		3.3		263		3.5
Creditex		72		0.8		78		0.9		5		0.1

Total sales to our largest unregulated companies		2,601		28.6		2,394		27.7		1,910		25.4

Total sales to our largest customers		8,583		94.4		8,105		93.9		6,899		91.4

(1) The figures for Edelnor and Luz del Sur represent sales under bilateral contracts with Edegel only, and not withdrawals of these companies assigned to Edegel for non contract-related consumption. The energy sold to these distributors includes the amount granted to Edegel in the bids realized since 2006.

(2) Edelnor reduced its consumption in 2012 compared to 2011 due to the termination of a contract in force since 1997 and the reduction in the dispatch of another two contracts.

(3) Hidrandina and ElectroSur have been customers since 2012. Edegel entered into bilateral contracts with each customer at the bar price between January 2012 and December 2012 and between January 2012 and December 2013, respectively.

Our most important competitors in Peru are Enersur (GDF-Suez group, with an installed capacity of 1,225 MW); ElectroPerú (state-owned competitor, with an installed capacity of 1,043 MW); Kallpa (Inkia Energy group, with an installed capacity of 857 MW) and Egenor (Duke Energy Group, with an installed capacity of 622 MW).

Electricity Transmission Business Segment

CIEN

CIEN is wholly-owned by Endesa Brasil, and we hold a 54.3% economic interest in CIEN. CIEN consolidates CTM and TESA, which operate the Argentine side of the interconnection line between Argentina and Brazil. In 2012, CIEN represented 1.1% of our operating revenues and 2.5% of our operating income, both before consolidation adjustments. Since April 2011, CIEN has been recognized by the local authority as a “regulatory asset” and therefore is a participant in the basic Brazilian grid. Therefore, it will receive fixed payments called Permitted Annual Compensation (RAP).

CIEN allows for the energy integration of Mercosur and the import and export of electricity between Argentina, Uruguay and Brazil. It has two transmission lines covering a distance of 500 kilometers between Rincón in Argentina and the Santa Catarina substation in Brazil, and a total installed capacity of 2,100 MW.

Electricity Distribution Business Segment

Our electricity distribution business is conducted in Chile through Chilectra, in Argentina through Edesur, in Brazil through Ampla and Coelce, in Colombia through Codensa and EEC, and in Peru through Edelnor. For the year ended December 31, 2012 electricity sales increased by 5% compared to 2011, totaling 73,104 GWh. For more information on energy sales by our distribution subsidiaries for the past five fiscal years, see “Item 3. Key Information — A. Selected Financial Data.” Currently, Chilectra is the technical operator of Edesur, Edelnor, Ampla and Coelce, but does not receive operator fees.

Chilectra

Chilectra is one of the largest electricity distribution companies in Chile in terms of the number of the regulated clients, distribution assets and energy sales. Chilectra had consolidated operating income of Ch$ 134 billion for the year ended December 31, 2012. Our economic interest in Chilectra is 99.1%. Chilectra operates in a concession area of 2,118 square kilometers. Chilectra transmits and distributes electricity in 33 municipalities of the Metropolitan Region. Its service area is defined primarily as a high density area under the Chilean tariff regulations governing electricity distribution companies and includes all residential, commercial, industrial, governmental, and toll customers. The Metropolitan Region, where the capital city of Santiago is located, is Chile’s most densely populated area and has the highest concentration of industries, industrial parks and office facilities in the country. As of December 31, 2012, Chilectra distributed electricity to approximately 1.7 million customers. Chilectra also has direct equity stakes in foreign distribution subsidiaries controlled by us. Chilectra’s energy losses were 5.4% in 2012, compared to 5.5% in 2011. This decrease in energy losses is due to the effectiveness of energy loss plans focused on technical inspections and loss management, among others.

For the fiscal year ended December 31, 2012, residential, commercial, industrial and other customers, who are primarily public and municipal, represented 26%, 29%, 21% and 24%, respectively, of Chilectra’s total energy sales of 14,445 GWh, which is an increase of 5.5% in comparison with 2011. For the year ended December 31, 2012, revenues from electricity sales were Ch$ 860 billion. Total energy purchases reached Ch$ 645 billion, of which Ch$ 181 billion were from Endesa Chile, a decrease in comparison with 2011, when Ch$ 186 billion were purchased from Endesa Chile.

Edesur

Edesur is the second largest electricity distribution company in Argentina in terms of energy purchases after Edenor, an unrelated company. Our economic interest in Edesur is 65.4%. Edesur operates in a concession area of 3,309 square kilometers. Edesur distributes electricity in the south-central part of the greater Buenos Aires metropolitan area. Its service area comprises the major business district of Buenos Aires and several residential areas of the southern part of Buenos Aires. As of December 31, 2012, Edesur distributed electricity to 2.4 million customers. Residential, commercial, industrial and other customers, primarily public and municipal, represented 43%, 25%, 8% and 24%, respectively, of Edesur’s total energy sales. It had energy losses of 10.6% in 2012, compared to 10.5% in 2011. For the year ended December 31, 2012, revenues from electricity sales amounted to Ch$ 293 billion. In 2012, Edesur’s electricity sales were 17,738 GWh. Total energy purchases were Ch$ 175 billion.

Ampla

Ampla is the second largest electricity distribution company in the State of Rio de Janeiro, Brazil in terms of the number of clients and annual energy sales. As of December 31, 2012, we owned a 70.2% economic interest in Ampla. Ampla is engaged mainly in the distribution of electricity to 66 municipalities of the State of Rio de Janeiro and serves 2.7 million customers in a concession area of 32,615 square kilometers, with an estimated population of 8.0 million. As of December 31, 2012, residential, commercial, industrial and other customers represented 40%, 20%, 9% and 31%, respectively, of Ampla’s total sales of 10,816 GWh. For the year ended December 31, 2012, revenues from electricity sales were Ch$ 888 billion. As of December 31, 2012, Ampla’s energy losses were 19.6%, compared to 19.7% in 2011. Total energy purchases were Ch$ 319 billion.

Coelce

We hold a 35.3% economic interest in Coelce, the sole electricity distributor in the State of Ceará in northeastern Brazil. As of December 31, 2012, Coelce served over 3.3 million customers within a concession area of 148,825 square kilometers. During 2012, Coelce had annual sales of 9,878 GWh, an increase of 10.1% in comparison with 2011. In 2012, revenues from electricity sales were Ch$ 722 billion.

As of December 31, 2012, residential, commercial, industrial and other customers represented 34%, 19%, 12% and 36%, respectively, of Coelce’s total energy sales. As of such date, Coelce’s energy losses were 12.6%, compared to 11.9% in 2011. Total energy purchases were Ch$ 350 billion, 33% of which were purchased from Endesa Fortaleza and 67% from others suppliers.

Codensa

We hold a 21.7% economic interest in Codensa. However, due to a transfer of rights from another Endesa Spain subsidiary, we appoint the majority of the Board members and control this company. Codensa is an electricity distribution company that serves a concession area of 14,087 square kilometers in Bogotá and 96 other municipalities in the Department of Cundinamarca, Tolima and Boyacá. More than 9.6 million people live in Codensa’s service area, where it serves approximately 2.6 million customers. For the year ended December 31, 2012, revenues from electricity sales were Ch$ 702 billion. During 2012, Codensa’s annual sales reached 12,972 GWh, an increase of 3.3% in comparison with 2011. Of these sales, residential, commercial, industrial and other customers represented 34%, 16%, 7% and 43%, respectively.

Since 2001, Codensa only services regulated clients. The unregulated market is serviced directly by our generation company, Emgesa, with the exception of the public lighting in Bogotá. In 2012, Codensa had energy losses of 7.3%, compared to 7.8% in 2011. Total energy purchases were Ch$ 348 billion, 51% of which were purchased from Emgesa and 49% from other suppliers.

On September 25, 2012, CREG established the energy losses target of 9.61% that will be recognized in Condesa´s distribution tariff for the next five years.

EEC

We hold a 8.8% economic interest in EEC, an electricity distribution company that serves a concession area of 5,186 square kilometers in the Department of Cundinamarca. It serves approximately 125,000 customers. For the year ended December 31, 2012, revenues from electricity sales were Ch$ 35 billion. EEC’s annual sales reached 392 GWh, a 28.5% increase compared to 2011, and energy losses decreased to 13.4%, compared to 20.2% in 2011. Total energy purchases were Ch$ 12 billion.

Edelnor

As of December 31, 2012, we owned a 57.5% economic interest in Edelnor, our Peruvian electricity distribution company. Edelnor operates in a concession area of 1,517 square kilometers. This figure differs from the previously disclosed information as the concession area was reviewed in 2012 and was updated to reflect the new measurement. For the year ended December 31, 2012, the company had revenues from electricity sales of Ch$ 355 billion. Edelnor has an exclusive concession to distribute electricity in the northern part of the Lima metropolitan area, some provinces of the Lima department, such as Huaral, Huaura, Barranca and Oyón, and in the adjacent province of Callao. As of December 31, 2012, Edelnor distributed electricity to approximately 1.2 million customers, an increase of 5.2% from December 31, 2011. For the year ended December 31, 2012, Edelnor had total energy sales of 6,863 GWh, an increase of 4.4% over 2011. Edelnor had energy losses of 8.2% in 2012, which was the same as 2011. Total energy purchases reached Ch$ 221 billion, of which 40% was from the related parties Edegel and EEPSA.

Non-Electricity Businesses

Inmobiliaria Manso de Velasco (Chile)

Inmobiliaria Manso de Velasco, a wholly-owned subsidiary, develops real estate projects in Chile and represents less than 0.3% of our 2012 operating revenues before consolidation adjustments.

ELECTRICITY INDUSTRY REGULATORY FRAMEWORK

The following chart shows a summary of the main characteristics of the electricity regulatory framework by business segment for the five countries in which we operate.

Argentina

Brazil

Chile

Peru

Colombia

Unregulated Market. .

Spot markets with audited cost

Spot market with
auctioned cost
(Price-offered)

Regulated . . . . . . . . . .

Seasonal Price

Auction 15 years

for Thermal /

30 years for Hydro

Node Price
auction 15 years

Node Price
auction 20 years

Auction 3/5
years

Capacity . . . . . . . . . . . .

Contribution
peak demand

—

Income based on contributions during peak demand

Firm energy
contribution
(energy auctions
for at least 20
years)

Features . . . . . . . . . . . .

Public - Open Access - Regulated Tariff –

Monopoly Regime for Transmission System Operators (“TSOs”)

Law . . . . . . . . . . . . . . .

Concession contract

Administrative Concession

(indefinite)

Authorization
Operation Zone

Expansion . . . . . . . . . .

95 years

30 years

Undefined

Tariff review . . . . . . . .

5 years

4/5 years

4 years

5 years

Unregulated Agents . .

> 0.03 MW

> 0.5 MW

> 0.2 MW

> 0.1 MW

Liberalized (%) . . . . . .

≈ 20%

≈25%

≈30%

≈45%

≈30%


Gx: Generation		Tx: Transmission		Dx: Distribution		Cx: Trading

Chile

Industry Overview

Industry Structure

The Chilean electricity industry is divided into three business segments: generation, transmission and distribution. These business segments are carried out by publicly-owned private sector companies. The state’s role is circumscribed to regulation, supervision and indicative investment planning through non-binding recommendations in the case of the generation and transmission businesses, with the exception of the main transmission system in which indicative planning is binding as well as part of the bidding processes for its construction.

The following chart shows the relationships among the various actors in the Chilean market:

LOGO

The generation segment comprises a group of electricity companies who own generating plants, which energy is transmitted and distributed to end customers. This segment is characterized by being a competitive market which operates under market-driven conditions. They sell their production to distribution companies, unregulated customers, other generation companies, and their surpluses on the spot market.

The transmission system comprises a combination of lines, substations and equipment for the transmission of electricity from the production points (generators) to the centers of consumption or distribution. Transmission in Chile is defined as lines or substations with a voltage or tension higher than 23 kV. The transmission system is open access and transmission companies may impose rights of way over the available transmission capacity through the payment of tolls.

The distribution segment is defined for regulatory purposes as all electricity supplies to end customers at a voltage no higher than 23 kV. Distribution companies operate under a distribution public utility concession regime, with service obligation and regulated tariffs for supplying regulated customers.

The distribution companies supply both regulated customers, whose demand is less than 500 kW, a segment for which the price and supply conditions are the result of tender processes regulated by the government’s National Energy Commission, and unregulated customers, with bilateral agreements with the generators, whose conditions are freely negotiated and agreed.

Customers are classified according to their amount of demand, as follows: (i) unregulated customers, those with a connected capacity over 2,000 kW; (ii) regulated customers, whose connected capacity is no more than 2,000 kW; and (iii) customers that opt for either a regulated-tariff or an unregulated regime, for a minimum period of four years in each regime, available to customers whose connected capacity falls in the range of 500 kW-2,000 kW.

In Chile, there are four separate interconnected electricity systems. The main systems that cover the most populated Chilean areas are the SIC, which services the central and south central part of the territory, where 92% of the Chilean population lives, and the SING, which operates in the northern part of the country, where most of the mining industry is located, and where 6% of the Chilean population lives (figures based on preliminary result of the 2012 Chilean census). In addition to the SIC and the SING, there are two isolated systems in southern Chile that provide electricity to remote areas, where 2% of the population lives.

In 2012, the government announced the interconnection project between the SIC and the SING, which would consider the use of a 500 kV high-voltage direct current (“HVDC”) technology with a capacity of 1,500 MW. This project would join the Cardones substation in the SIC and a new substation in the SING called Nuevo Encuentro. For its development, technical studies and the corresponding bidding process will be required in order to carry out the interconnection project. The start-up is expected for 2019.

The operation of electricity generation companies in each of the two major interconnected electricity systems is coordinated by their respective dispatch center, or CDEC, an autonomous entity that involves generators, transmission companies and large customers. A CDEC coordinates the operation of its system with an efficiency criterion in which the lowest cost producer available is usually required to satisfy demand at any moment in time. As a result, at any specific level of demand, the appropriate supply will be provided at the lowest possible production cost available in the system. The marginal cost used is the price at which generators trade energy on an hourly basis, involving both their injections into the system and their withdrawals or purchases for supplying their customers.

Principal Regulatory Authorities

The Chilean Ministry of Energy develops and coordinates plans, policies and standards for the proper operation of the sector, approves tariffs and node prices set by the Chilean National Energy Commission ( “CNE”), and regulates the granting of concessions to electricity generation, transmission and distribution companies.

The CNE is the technical entity in charge of defining prices, technical standards and regulatory requirements.

The Chilean Superintendency of Electricity and Fuels (“SEF”) monitors the proper operation of electricity, gas and fuel sectors in compliance with the law in terms of safety, quality, and technical standards.

The Chilean Ministry of Environment is responsible for the development and application of regulatory and policy instruments that provide for the protection of natural resources, the promotion of environmental education and the control of pollution, among other matters. It is also responsible for administering the environmental impact assessment system at the national level, coordinating the preparation of environmental standards and establishing the programs for compliance with the standards.

The Anti-Trust Entities are responsible for preventing, investigating and correcting any threats to free market competition and any anti-competitive practices by potentially monopolistic companies. These entities include:

•

Free Market Competition Tribunal (“TDLC”, in its Spanish acronym). This is a special and independent jurisdictional entity, subject to the directive, correctional and economic authority of the Supreme Court, whose function is to prevent, correct and sanction threats to free market competition.

•

National Economic Prosecutor (“FNE”, in its Spanish acronym). This is the attorney general responsible for economic matters and for investigating and prosecuting all antitrust conduct before the Resolutory Commission and other tribunals.

The Panel of Experts acts as a tribunal in electricity matters arising from disputes between participants in the electricity market and the regulatory authority in certain tariff processes. It issues enforceable resolutions and comprises experts in industry matters, five engineers or economists and two lawyers, all of whom are elected every six years by the Free Market Competition Tribunal.

There are also other entities related to the energy sector: the Chilean Nuclear Energy Committee in charge of research, development, use and control of nuclear energy, and the Chilean Energy Efficiency Agency, in charge of promoting energy efficiency.

The Electricity Law

General

Since its inception, the Chilean electricity industry has been developed by private sector companies. Nationalization was carried out during the period 1970-73. During the 1980s, the sector was reorganized through the Chilean Electricity Law or Decree with Force of Law (“DFL”) No. 1, allowing participation of private capital in the electricity sector. By the end of the 1990s, foreign companies had a majority participation in the Chilean electricity system.

The goal of the Chilean Electricity Law is to provide incentives to maximize efficiency and to provide a simplified regulatory scheme and tariff-setting process which limits the discretionary role of the government by establishing objective criteria for setting prices. The expected result is an economically efficient allocation of resources. The regulatory system is designed to provide a competitive rate of return on investment to stimulate private investment, while ensuring the availability of electricity to all who request it.

DFL No. 1 was published in 1982 and has had only two important changes since then. The first one took place in 2004 to encourage investments in transmission lines. The second one was in 2005 to create long-term contracts between generation and distribution companies as part of a bid process.

The present text of the law was restated in DFL No. 4 of 2006, which is complemented with a series of regulations and standards.

In February, 2012, the Chilean government presented the “National Energy Strategy” which seeks to be a guide for the system’s development over the next 20 years. This strategy is based on six pillars: improving energy efficiency; promoting Non-Conventional Renewable Energies (“NCREs”); reinforcing the role of conventional renewable energies to reduce external dependence; achieving a new focus on transmission by creating a public electricity highway; increasing sector competitiveness and progress in international electricity interconnection studies. The first step to achieve this strategy was the presentation of the “Electricity Highway” project, which currently is in discussion in the Chilean Congress.

Limits and Restrictions

The owners of the main transmission system must be constituted as limited liability stock corporations and cannot take part in the electricity generation or distribution businesses.

Individual participation in the main transmission system (“STT”) by companies operating in another electricity or unregulated customer segment cannot exceed, directly or indirectly, 8% of the total investment value of the STT. The aggregate participation of all such agents in the STT must never exceed 40% of the investment value.

The water utility services law also sets restrictions on the overlapping of electricity distribution company concession areas with those of water distribution and sewage services.

There are no special or specific restrictions on generating activity in terms of market concentration.

Regulation of Generation Companies

Concessions

The law permits generation activity without a concession. However, companies may apply for a concession to facilitate access to third-party properties. Third-party property owners are entitled to compensation, which may be agreed to by the parties or, if there is no agreement, it may be determined by an administrative proceeding that may be appealed in the Chilean courts.

Dispatch and Pricing

In each transmission system, the pertinent CDEC coordinates the operations of generation companies, in order to minimize the operating costs in the electricity system and monitor the quality of service provided by the generation and transmission companies. Generation companies satisfy their contractual sales requirements with dispatched electricity, whether produced by them or purchased from other generation companies in the spot market.

Sales by Generation Companies to Unregulated Customers

Sales by generation companies may be made to final unregulated customers or to other generation companies under freely negotiated contracts. To balance their contractual obligations with their dispatch, generators have to trade deficit and surplus electricity at the spot market price, which is set hourly by each CDEC, based on the lowest cost of production of the next kWh to be dispatched.

Sales to Distribution Companies and Certain Regulated Customers

Prior to 2005, sales to distribution companies for resale to regulated customers were made through contracts at regulated prices set by the CNE (node prices) in effect at the relevant locations (or nodes) on the interconnected system through which such electricity was supplied. Since 2005, all new contracts between generation and distribution companies for the electricity supply to regulated customers must arise from international bids which have a maximum offer energy price based on the average price paid by the unregulated customers at the time that the bid takes place, which is calculated twice a year by the CNE. If a first bid is unsuccessful, authorities may increase this maximum price by an additional 15%. The bids are awarded on a minimum price basis. The average prices associated with these bids are transferred directly to end customers, replacing the regulated node price regime. During the term of the contracts, the energy and capacity prices are indexed according to formulas set forth in the bid documentation and linked to fuel, investment and other costs of energy generation. Under the bid system, all distribution companies have separate electricity contracts for their regulated and unregulated customers since 2010.

Due to the bankruptcy of the generating company Campanario in September, 2011, certain regulated customers in the central-southern region of the country no longer had electricity contracts. In response, the Chilean government published two resolutions: RE 2288 and RM 239. Pursuant to these resolutions, all generating companies must meet demand from their customers on a pro rata basis to their injections into the system until new contracts are awarded under new tendering processes. As of the date of this Report, only 56% of this energy has been awarded to generation companies until December, 2014 (of which 50% was to Endesa Chile and 6% to Gener).

Sales of Capacity to Other Generation Companies

Each CDEC determines a firm capacity for each power plant on an annual basis. Firm capacity is the highest capacity which a generator may supply to the system at certain peak hours, taking into consideration statistical information and accounting for time out of service for maintenance purpose and for extremely dry conditions in the case of hydroelectric plants.

A generation company may be required to purchase or sell capacity in the spot market, depending upon its contractual requirements in relation to the amount of electricity to be dispatched from such company and to its firm capacity.

Regulatory Charges

Chilean laws have not established any specific charge for the electric system. Nevertheless, if the tariff for residential customers increases by more than 5% in a six-month period, the government can establish a subsidy for low-income families. The last subsidy was granted by the government in 2009.

Incentives and Penalties

If a rationing decree is enacted in response to prolonged periods of electricity shortages, strict penalties may be imposed on generation companies that contravene the decree. A severe drought is not considered a force majeure event.

Generation companies may also be required to pay fines to the regulatory authorities, related to system blackouts due to any generator’s operational mistake, including failures related to the coordination duties of all system agents, as well as to make compensatory payments to electricity customers affected by shortages of electricity. If generation companies cannot satisfy their contractual commitments to deliver electricity during periods when a rationing decree is in effect and there is no energy available to purchase in the system, the generation company must compensate the customers at the failure cost determined by the authority in each tariff setting. This failure cost, which is updated semiannually by the CNE, is a measurement of how many final customers would pay for one extra MWh under rationing conditions.

Regulation of Distribution Companies

Concessions

Distribution service concessions give the right to use public areas for building distribution lines. The concessions are given by the Chilean Ministry of Energy for an undefined period. Distribution companies have the obligation to serve and connect the customers that make the requirement in the concession area. The Chilean President can declare a concession expired if the quality of service does not meet certain minimum standards.

Energy Purchases

The first international auction for the supply to distribution companies’ regulated customers took place in 2006. Chilectra submitted bids in November 2006, July 2007 and March 2008, allocating 100% of the power requirements tendered for the 2010-2025 period. Prices obtained by Chilectra as part of these tenders are consistent with the system’s long-term expansion technology and prices are indexed to the CPI and the price of coal and LNG.

During 2010, Chilectra submitted bids allocating 75% of the power requirements tendered for the 2014-2029 period. A new bidding process will be held in 2013 for the remaining power requirements. If Chilectra is successful in being awarded this 2013 bid, Chilectra is expected to be able to meet the demand of its regulated customers through 2018.

Distribution Tariffs to Final Customers

The tariffs charged by distribution companies to final customers are determined by the sum of the cost of electricity purchased by the distribution company, a transmission charge and the value added from distribution of electricity (“VAD”), which allows distribution companies to recover their operating costs and includes a return on investment. The price for both generation and distribution capacity sold to customers includes a factor which reflects the simultaneous contribution of each customer to peak capacity demand of the system as a whole. The transmission charge reflects the cost paid for electricity transmission and transformation.

The VAD is based on a “model company” and includes the following: selling, general and administrative distribution costs; maintenance and operating costs of distribution assets; cost of efficient energy losses; and an expected return on investment, before taxes, of 10% per year in real terms based on the replacement cost of assets used for the distribution business.

Toward this end, the CNE selects a real distribution company, to which it applies efficiency guidelines, which result in a cost structure for a hypothetical “model company” for each Typical Distribution Area (“TDA”) as described below. The rate is not based on actual costs incurred by any given distribution company, but on investment, operating, maintenance and general administrative standards and overall efficiency of operations for the model company.

Distribution Tariff-Setting Process

The VAD is set every four years. The CNE classifies companies into groups, according to the TDA, based on economic factors that group companies with similar distribution costs due to population density, which determines equipment requirements in the network.

The real return on investment for a distribution company depends on its actual performance relative to the standards chosen by the CNE for the model company. The tariff system allows for a greater return to distribution companies that are more efficient than the model company. Tariff studies are performed by the CNE and distribution companies. Preliminary tariffs are calculated as a weighted average of the results of the CNE-commissioned study and the companies’ study, with the results of the CNE’s study bearing twice the weight of the companies’ study. Preliminary tariffs are then tested to ensure that they provide a rate of return between 6% and 14% of the replacement cost of electricity-related distribution assets for the entire business sector.

As of the date of this Report, the CNE is finishing the last details of the tariff-setting process for distribution companies for the four year period from November 2012 to November 2016. Once the process finished, the new tariff will be retroactively applied.

Ancillary Electrical Services

The CNE is currently in the process of finishing the ancillary services study, through which it will set the prices for services such as meter rental services and reconnection of electricity to the final customer. These new prices will apply from the respective decree’s publication and last through 2016.

Incentives and Penalties

Distribution companies may be required to compensate final customers if there are shortages of electricity that exceed the authorized standards. These compensatory payments shall be at an amount equal to double the non-supplied energy at a value equivalent to the failure cost.

Regulation in Transmission

The main transmission system consists of 220 kV or higher voltage lines that are used by generators and customers. Every four years a study is done to evaluate the existing system and to define the expansion plan. On December 31, 2010, the last study was delivered to the CNE. In November, 2011, the CNE promulgated Decree 61 that defines the current value of the existing lines to be remunerated in the 2011-2014 period. The main transmission system is paid by generators and customers.

According to the modifications to the General Electricity Services Law incorporated in Law 19,940 of March, 2004, the transportation of electricity by main transmission systems and sub-transmission systems are defined as a public service. Therefore, the transmitter has a service obligation, and is responsible for the maintenance and improvement of its facilities.

On September 4, 2012, the Chilean government sent to the Chilean Congress a bill called “Electricity Highway,” which seeks to define transmission projects as being of “public interest”. This designation would permit the creation of fiscal sections, which are currently susceptible to being expropriated or subject to easements, speed up the licensing and permits process and thereby ensure the sector’s development.

Regulation in Subtransmission

Subtransmission systems are defined as voltage lines exceeding 23 kV. There are seven subtransmission systems defined by decree. The subtransmission systems are paid mainly by customers according to the values fixed by decree of the Ministry of Energy. Generators and unregulated customers pay only for the lines they use in each system. The study to define the current value of the existing lines to be remunerated in the 2011-2014 period has been finished. However, as of the date of this Report, the CNE has not promulgated the corresponding decree.

Environmental Regulation

The Chilean Constitution grants citizens the right to live in a pollution-free environment. It further provides that certain other constitutional rights may be limited in order to protect the environment. Chile has numerous laws, regulations, decrees and municipal ordinances that address environmental considerations. Among them are regulations relating to waste disposal (including the discharge of liquid industrial wastes), the establishment of industries in areas in which they may affect public health, and the protection of water for human consumption.

Environmental Law 19,300 was enacted in 1994 and implemented by several rules, such as the Environmental Impact Assessment System Rule issued in 1997 and modified in 2001. This law requires companies to conduct an environmental impact study and a declaration of any future generation or transmission projects.

In January, 2010, Law 19,300 was modified by Law 20,417, which introduced changes in the environmental assessment process and in the public institutions involved, principally creating the Chilean Ministry of Environment and the Superintendency of Environment. Consequently, the environmental assessment process is coordinated by this entity and the Environmental Assessment Service.

On April 1, 2008, Law 20,257 was enacted, which amended the General Services Law. The purpose of the amendment is to promote the use of NCRE. This law defines the different types of technologies considered as NCRE, and establishes the obligation for generators, between 2010 and 2014, to supply at least 5% of the total energy contracted as of August 31, 2007, to be of such type, and to progressively increase this percentage 0.5 percentage points annually up to at least 10% as of 2024. Currently, our power plants recognized as NCRE generators are the Palmucho and Canela wind farms and the Ojos de Agua mini-hydroelectric plant. Additionally, the law sets forth fines for generators that do not comply with this obligation. Enersis fully complied with this obligation during 2012. The additional cost of generating with NCRE is being charged as a pass-through in the new contracts, thus eliminating an impact to our revenues.

An amendment to this law has been discussed in the Chilean Congress. The Chilean Senate unanimously approved an increase in the NCRE targets, initially from 10% in 2024 to 20% in 2020. The Minister of Energy has explained to the Chilean Energy and Mining Commission the technical and economic difficulties that this drastic change in the original target would cause. It was therefore recommended not to amend the present law in terms of targets.

In January 2011, Decree 13 of the Ministry of Environment was published in the Diario Oficial, a governmental publication, establishing emission standards for thermoelectric plants applicable to generation units of at least 50 MW. The object of this regulation is to control atmospheric emissions of particulate matter (MP), nitrogen oxides (NOx), sulfur dioxide (SO2) and mercury (Hg), in order to prevent and protect the health of the population and protect the environment. Existing emission sources will have to meet emission limits for MP as established in the regulation within two and a half years from the date of publication of this decree (which is expected to be in July 2013); for SO2 and NOx emissions, the term is four years in highly polluted areas and five years elsewhere.

In June 2012, Law 20,600 was published, creating the Environmental Courts. The law defines the Environmental Courts as special jurisdictional courts subject to the control of the Supreme Court. Their primary function is to resolve environmental disputes within their jurisdiction and look into other matters that are submitted for their attention under the law. The law created three such courts : the first began operating in December, 2012 and the other two will become operative in June, 2013.

On December 28, 2012, the Superintendency of Environment was formally created and began to exercise its powers of enforcement and sanctions pursuant to Chilean environmental regulations.

Water Rights

Our subsidiary, Endesa Chile, owns unconditional, absolute and perpetual property water rights granted by the Chilean Water Authority. Companies in Chile must pay an annual fee for unused water rights. License fees already paid may be recovered through monthly tax credits commencing on the start-up date of the project associated with the water right considered. The maximum license fees to be recovered are those paid during the eight years before the start-up date. As of the date of this Report, Enersis’ subsidiaries have not recovered any license fees already paid. During 2012, we paid Ch$ 6,429 million for 2011 unused water rights located in the SIC area. This amount may vary in the future according to the actual water rights we may hold each year. Enersis’ subsidiaries continuously analyze which water rights they will maintain, disregard or acquire. We estimate that in 2013 we will pay fees for an aggregate of Ch$ 7,269 million. Since 2012, the annual fees increased due to the water rights law, which requires a doubling of the annual fee for 2012. After that, the fees will remain flat for five years, and then double again thereafter. In the case of water rights located in the extreme south of Chile, outside the area comprised by the SIC, companies have began to pay license fees began starting from January 1, 2012. In this area, Endesa Chile owns water rights for the Futaleufú River.

Argentina

Industry Overview

Industry Structure

In the Wholesale Electricity Market ( “Argentine MEM” , in its Spanish acronym) there are four categories of local agents (generators, transmitters, distributors and large customers) and external agents (traders of generation and traders of demand) who are allowed to buy and sell electricity as well as related products.

The following chart shows the relationships among the various actors in the Argentine MEM:

LOGO

The generation sector is organized on a competitive basis, with independent generators selling their output in the Argentine MEM’s spot market or through private contracts to purchasers in the Argentine MEM’s contract market or to CAMMESA, which is the entity in charge of the operation of the Argentine MEM, through special transactions like contracts under Resolutions SE 220/2007 and 724/2008.

The transmission sector operates under monopoly conditions and is comprised of several companies to whom the Argentine government grants concessions. One concessionaire operates and maintains the highest voltage facilities and eight concessionaires operate and maintain high and medium voltage facilities, to which generation plants, distribution systems and large customers are connected. The international interconnected transmission systems also require concessions granted by the Argentine Secretariat of Energy. Transmission companies are authorized to charge different tolls for their services.

Distribution is regarded as a public service operating under monopoly conditions. It is comprised of companies that have been granted concessions by the Argentine government. Distribution companies have the obligation to make electricity available to end customers within a specific concession area, regardless of whether the customer has a contract with the distributor or directly with a generator. Accordingly, these companies have regulated tariffs and are subject to quality service specifications. Distribution companies may obtain electricity on the Argentine MEM’s spot market, at a price called “seasonal price,” which is defined by the Argentine Secretariat of Energy as the cap for the costs of electricity bought by distributors that can be passed through to regulated customers.

There are two electricity distribution areas subject to federal concessions. The concessionaires are Edesur (controlled by us) and Edenor (unrelated to us) which are located in the Greater Buenos Aires area. The local distribution areas are subject to concessions granted by the provincial or municipal authorities. However, all distribution companies acting on the Argentine MEM must operate under its rules.

Regulated customers are supplied by distributors at regulated tariffs, unless they have a minimum capacity demand of 30 kW, in which case they can choose to contract their supply directly from generators within the Argentine MEM’s spot market and thereby become “Large Customers” who may freely negotiate their prices with generating companies.

“Large Customers” are classified into three categories: Major Large Customers, Minor Large Customers and Particular Large Customers. Each of these categories of customers has different requirements with respect to purchases of their energy demand. For example, Major Large Customers are required to purchase 50% of their demand through supply contracts and the remainder in the spot market, while Minor Large Customers and Particular Large Customers are required to purchase all of their demand through supply contracts. Large customers participate in CAMMESA by appointing two acting and two alternate directors through the Asociación de Grandes Usuarios de Energía Eléctrica de la República Argentina (Argentine Association of Electric Power for Large Customers, or “AGUEERA”).

There is one interconnected system, the Argentine SADI, in its Spanish acronym, and smaller systems that provide electricity to specific areas. According to the Argentine National Institute of Statistics and Census (“INDEC”), 97.7% of the population received electricity through the public network in 2010, while 1.1% generated their own electricity and 1.2% had no access to electricity.

Principal Regulatory Authorities

The Argentine Ministry of Federal Planning, Public Investment and Services, through the Argentine Secretariat of Energy, is primarily responsible for studying and analyzing the behavior of energy markets, preparing the strategic planning with respect to electricity, hydrocarbons and other fuels, promoting policies to increase competition and improve efficiency in the assignment of resources, leading actions for applying the sector policy, orienting new operators to the general interest, respecting the rational exploitation of the resources and the preservation of the environment.

The Electricity National Regulatory Agency (“ENRE”, in its Spanish acronym) carries out the measures necessary for meeting national policy objectives with respect to the supply, transmission and distribution of electricity. Its principal objectives are to protect the rights of customers, promote competitiveness in production and encourage investments that assure long-term supply, promote free access, non-discrimination and the generalized use of the transmission and distribution services, and regulate transmission and distribution services to ensure fair and reasonable tariffs, encourage private investment in production, transmission and distribution, ensuring the competitiveness of the markets where possible.

The principal functions of the Administrative Company for the Wholesale Electricity Market (“CAMMESA”, in its Spanish acronym) are the coordination of dispatch operations, the establishment of wholesale prices and the administration of economic transactions made through the SIN. It is also responsible for executing the economic dispatch through economic considerations and rationality in the administration of the energy resource, coordinating the centralized operation of the SIN to guarantee its security and quality, and managing the Argentine MEM, in order to ensure transparency through the participation of all the players involved and with respect to the respective regulations.

The principal functions of the Argentine Federal Electricity Council are the following: (i) administering specific funds for the electricity sector and (ii) advising the national executive authority and the provincial governments with respect to the electricity industry, the priorities in performing studies and works, concessions and authorizations, and prices and tariffs in the electricity sector. It also provides advice regarding modifications resulting from legislation referring to the electricity industry.

The Electricity Law

General

The Argentine electricity industry was originally developed by private companies. As a result of service problems, the government began to intervene in the sector in the 1950s and initiated a nationalization process. Law 15,336/60 was passed to organize the sector and establish the federal legal framework for the start of major transmission and generation works. Many state companies were created within this framework in order to carry out various hydroelectric and nuclear projects.

As a result of the electricity shortage in 1989, the following laws were passed starting in 1990: Law 23,696 (“State Reform”), Law 23,697 (“Economic Emergency”) and Law 24,065 (“Electricity Framework”).

The objective of the new legislations was essentially to replace the vertically-integrated system based on a centrally-planned state monopoly with a competitive system based on the market and indicative planning.

Regulatory Developments: The Industry After the Public Emergency Law

Law 25,561, the Public Emergency Law, was enacted in 2002 to manage the economic crisis which began that year. It forced the renegotiation of public service contracts (such as electricity transmission and distribution concession contracts) and imposed the conversion of U.S. dollar denominated obligations into Argentine pesos at a pegged rate of Ar$ 1 per US$ 1. The mandatory conversion of transmission and distribution tariffs from U.S. dollars to Argentine pesos at this pegged rate (compared to the market exchange rate of approximately Ar$ 3 per US$ 1) and the regulatory measures that cap and reduce the spot and seasonal prices hindered the pass-through of generation variable costs in the tariffs to end customers.

The Public Emergency Law also empowered the Argentine government to implement additional monetary, financial and foreign exchange measures to overcome the economic crisis in the medium term. These measures have been periodically extended. Law 26,729, which was enacted in December 2011, extended the measures until December 31, 2013.

The Argentine Secretariat of Energy introduced several regulatory measures aimed at correcting the effects of the devaluation into the Argentine MEM’s costs and prices and to reduce the price paid by the end customers.

Resolution SE 240/2003 changed the method for calculating spot prices by decoupling such prices from the marginal cost of operation. Prior to this resolution, spot prices in the Argentine MEM were typically fixed by units operating with natural gas during the warm season (from September through April) and units operating with liquid fuel/diesel in the winter (May-August). Due to restrictions on natural gas supply, winter prices were higher and affected by the price of imported fuels priced in U.S. dollars. Resolution SE 240/2003 sought to avoid price indexation pegged to the U.S. dollar and, although generation dispatch is still based on actual fuels used, the calculation of the spot price under the resolution is defined as if all dispatched generation units did not have the existing restrictions on natural gas supply. In addition, water value is not considered if its opportunity cost is higher than the cost of generating with natural gas. The resolution also set a cap on the spot price at Ar$ 120/MWh, which was still valid during 2012. The real variable costs of thermal units burning liquid fuels were paid by CAMMESA through the Transitory Additional Dispatch Cost (Sobrecosto transitorio de despacho, or “STD”) plus a margin of Ar$ 2.5/MWh, according to the Resolutions SE 6,866/2009 and 6,169/2010, that came into effect in May 2010.

The government has avoided the increase in electricity tariffs to end customers and seasonal prices have been maintained substantially fixed in Argentine pesos. However, gas producers have received price revisions by the authority and thereby were able to recover part of the value that they lost as a result of the 2002 devaluation.

Under this system, CAMMESA sells energy to distributors who pay seasonal prices, and buys energy from generators at spot prices that recognize rising gas prices at a contractual price defined by the instructions of the Argentine Secretariat of Energy. To overcome this imbalance, the Argentine Secretariat of Energy — through Resolution SE 406/2003 — only allows payments to generators for amounts collected from the purchasers in the spot market. This resolution set a priority of payment for different services , such as capacity payment, fuel cost and energy sales margin, among others. As a result, CAMMESA accumulates debt with generators while the system gives a misleading price incentive to the market that encourages electricity consumption but discourages investments to satisfy the growth in electricity demand, including investments in transmission capacity. Additionally, generators suffer a reduction of estimated income from contract prices because of the reduction of the spot price level.

The Argentine government has gradually reversed its decision to freeze tariffs. During 2011, various resolutions authorizing the elimination of electricity and natural gas subsidies were issued. However, the subsidy elimination has been applied to only 5% of the demand. For further details, see “— Sales to Distribution Companies and Certain Regulated Customers” below.

In order to enhance the energy supply, the Argentine Secretariat of Energy created different schemes to sell “more reliable energy.” Resolution 1,281/2006 created the Energy Plus Service, which was designed to increase generation capacity in order to meet growth in electricity demand over the “Base Demand,” which was the demand for electricity in 2005.

Resolutions SE 220/2007 and 724/2008 gave thermal generators the opportunity to reduce some of the adverse effects of Resolution SE 406/2003 by entering into MEM Supply Commitment Contracts, or “CCAM”, in its Spanish acronym. Under these resolutions, a generator can perform maintenance or repowering investments to improve their unit’s availability and add additional capacity to the system. After authorization, the generator can then sign a CCAM at prices that would permit the recovery of such capital expenditures. Additionally, energy sales through a CCAM receive payment priority compared with spot energy sales under Resolution 406/2003). Generators with a CCAM can supply energy to CAMMESA for up to 36 months, renewable only for an additional period of six months.

During 2009, Resolution SE 762/2009 created the Hydroelectric National Program to promote the construction of new hydro plants. The program enables authorized generators to enter into energy supply contracts with CAMMESA for up to fifteen years at prices that would allow for the recoupment of their investment.

The Argentine government has adopted several other measures to encourage new investments, including the following: auctions to expand the capacity of natural gas transportation and electricity transmission; the implementation of certain projects for the construction of power plants; the creation of fiduciary funds to finance these expansions; and the awarding of contracts with renewable energy, called the “GENREN program”. For more details, refer to “— Environmental Regulation” below. In addition, Law 26,095/2006 created specific charges that must be paid by end customers which are used to finance new electricity and gas infrastructure projects. The Argentine government has also enacted some regulations to encourage the rational and efficient use of electricity.

Since the implementation of Law 24,065 (“Electricity Framework”), the generation sector has sold the electricity it generates on the wholesale spot market and the private contract market. However, a series of resolutions have been published in recent years that have permitted the Argentine government and generators to sign contracts for the incorporation of new generation and/or maintenance of existing plants to guarantee the availability of the units, all in accordance with Resolutions 146/23, 200/220/07 and 724/08.

On August 24, 2012 the Argentine government informed electricity sector companies that it will reform the Argentine MEM and end the marginalist system of the 1990s. To implement these changes, a Strategic Planning and Coordination Commission of the National Hydrocarbons Investment Plan was created. It is expected that the principal changes will be in the generation sector and that the “liberalized marginalist” model will evolve into a “Cost Plus” model in accordance with the following “Declared Principles”: (i) any income shall be applied to each company based on the sum of its equity and financial debt, less redundant assets, (ii) a “Reasonable Profit” would be recognized, and (iii) efficient operating costs would be recognized.

With this new regulatory model, the Argentine government will have more information and control over (i) the profitability of companies, (ii) the quality of service, and (iii) the supply of fuels through CAMMESA, which will be the sole supplier of fuels (through imports and a contract with YPF S.A., an Argentine company engaged in the exploration, distribution and sale of petroleum and its derivatives).

As of the date of this Report, the implementation date of the new regulatory model has not been determined.

Agreement For Managing And Operating Projects

On November 25, 2010, the Argentine Secretariat of Energy signed an agreement with several generation companies, including Enersis’ subsidiaries, in order to: (i) increase thermoelectric unit availability, (ii) increase energy and capacity prices and (iii) develop new generation units through the contribution of outstanding debts of CAMMESA owed to the generation companies.

This agreement seeks to accomplish the following: (i) continue the reform of the Argentine MEM; (ii) enable the incorporation of new generation to meet the increased demand for energy in the Argentine MEM (pursuant to this agreement, Endesa Chile’s subsidiaries, together with the SADESA Group and Duke, formed a company to develop the combined-cycle project with a capacity of approximately 800 MW at the Vuelta de Obligado thermal plant); (iii) determine a mechanism to pay the generators’ sales settlements with maturity dates to be determined (“LVFVDs”, in the Spanish acronym), which represent generators’ claims spanning the period from January 1, 2008 to December 31, 2011; and (iv) determine the method for recognizing the total remuneration due to generators.

On October 24, 2012, the contract for the turnkey supply and construction of the Vuelta de Obligado plant was entered into by and among General Electric Internacional Inc. and General Electric Internacional Inc., Argentina branch, and the Argentine Secretariat of Energy.

The project also includes the expansion of the Río Coronda 500 kV transformer station which connects to the Argentine Interconnected System (“Argentine NIS”) , the construction of four new fuel tanks, the construction of a gas pipeline to supply natural gas from the national network, and maintenance of the plant during the single and combined-cycle operation periods for a period of 10 years.

FONINVEMEM

Resolution SE 712/2004 created FONINVEMEM, a fund whose purpose is to increase electricity capacity/generation within the Argentine MEM. Pursuant to Resolution SE 406/2003, the Argentine Secretariat of Energy decided to pay generators for the spot prices up to the amount available in a stabilization fund, after collecting the funds from the purchasers in the spot market at seasonal prices, which were lower than spot prices for the same period. FONINVEMEM would receive the differences between spot prices and payments to sellers, according to Resolution SE 406/ 2003 from January 1, 2004 to December 31, 2006. CAMMESA was appointed to manage FONINVEMEM.

Pursuant to Resolution SE 1,193/2005, all private generators in the Argentine MEM were called upon to participate in the construction, operation and maintenance of the electricity generation plants to be built with the funds from FONINVEMEM, consisting of two combined -cycle generation plants of approximately 850 MW each .

Due to the insufficient resources to construct the plants, Resolution SE 564/2007 required all of the Argentine MEM’s private sector generators to commit to FONINVEMEM by including the differences between spot prices and payments made pursuant to Resolution SE 406/2003 for an additional period ending December 31, 2007. These plants were completed in 2010 and are powered by natural gas or alternative fuels.

The Energy Plus Program

In September 2006, the Argentine Secretariat of Energy issued Resolution SE 1,281/2006 in an effort to respond to the continued increase in energy demand following Argentina’s economic recovery after the crisis. With this resolution the Argentine government started the Energy Plus Program. which principal objectives are to (i) create incentives to construct electricity generation plants and (ii) ensure that energy available in the market is used primarily to service residential customers and industrial and commercial customers with an energy demand is at or below 300 kW as well as those who do not have access to other viable energy alternatives.

The resolution also established the price large customers are required to pay for excess demand that are not covered by a contract under the Energy Plus Program, which is equal to the marginal cost of operations. This marginal cost is equal to the generation cost of the last generation unit dispatched to supply the incremental demand for electricity at any given time.

Limits and Restrictions

To preserve competition in the electricity market, participants in the electricity sector are subject to vertical and horizontal restrictions, depending on the market segment in which they operate.

Vertical Integration Restrictions

The vertical integration restrictions apply to companies that intend to participate simultaneously in different sub-sectors of the electricity market. These vertical integration restrictions were imposed by Law 24,065, and apply differently to each sub-sector as described below:

Generators

•

Neither a generation company nor any of its controlled or controlling companies can be an owner, majority shareholder or the controlling entity of a transmission company; and

•

Since a distribution company cannot own generation units, a holder of generation units cannot own distribution concessions. However, the shareholders of the electricity generator may own an entity that holds distribution units, either by themselves or through any other entity created with the purpose of owning or controlling distribution units.

Transmitters

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Neither a transmission company nor any of its controlled or controlling companies can be an owner, majority shareholder or the controlling company of a generation company;

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Neither a transmission company nor any of its controlled or controlling companies can be an owner, majority shareholder or the controlling company of a distribution company; and

•

Transmission companies cannot buy or sell electric energy.

Distributors

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Neither a distribution company nor any of its controlled or controlling companies can be an owner, majority shareholder or the controlling company of a transmission company; and

•

A distribution company cannot own generation units. However, the shareholders of an electricity distributor may own generation units either by themselves or through any other entity created with the purpose of owning or controlling generation units.

Horizontal Integration Restrictions

In addition to the vertical integration restrictions described above, distribution and transmission companies are subject to the following horizontal integration restrictions:

Transmitters

•

Two or more transmission companies can merge or be part of a same economic group only if they obtain an express approval from the ENRE. Such approval is also necessary when a transmission company intends to acquire shares of another transmission company. Pursuant to the concession agreements that govern the services rendered by private companies operating transmission lines between 132 kW and 140 kW, the service is rendered by the concessionaire on an exclusive basis in certain areas indicated in the concession agreement. Pursuant to the concession agreements that govern the services rendered by the private companies operating the high-tension transmission services of at least 220 kW, such companies must render the service on an exclusive basis and are entitled to render the service throughout the entire country, without territorial limitations.

Distributors

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Two or more distribution companies can merge or be part of a same economic group only if they obtain an express approval from the ENRE. Such approval is necessary when a distribution company intends to acquire shares of another transmission or distribution company; and

•

Pursuant to the concession agreements that govern the services rendered by private companies operating distribution networks, the service is rendered by the concessionaire on an exclusive basis in certain areas indicated in the concession agreement.

Regulation of Generation Companies

Concessions

Hydroelectric generators with a normal generation capacity exceeding 500kW must obtain a concession to use public water sources. Concessions may be granted for a fixed or an indefinite term.

Such concession-holders have the right to: (i) take control of the private properties within the concession area (subject to general laws and local regulations) that are necessary to create reservoirs as well as underground or above ground supply-line and release channels, (ii) flood lands that are necessary to raise water levels, and (iii) request the authorities to make use of the powers conferred in article 10 of Law 15,336 in cases where it is absolutely necessary to appropriate the property of a third-party that was not part of the concession and the concession-holder has failed to reach an agreement with such third-party.

Dispatch and Pricing

CAMMESA controls the coordination of dispatch operations, the spot price calculations and the administration of the Argentine MEM’s economic transactions. CAMMESA is also required to comply with special instructions given by the Argentine Secretariat of

Energy in order to enter into power purchase transactions with certain generators. All generators that are Argentine MEM agents have to be connected to the Argentine NIS and are obliged to comply with the dispatch order to generate and deliver energy to the Argentine NIS in order to be sold in the spot market or in the term market. Distribution companies, traders and large customers that have entered into private supply contracts with generation companies pay the contractual price directly to the generator and also pay a fee to the transmission and/or distribution company for the use of their systems.

The emergency regulations enacted after the Argentine crisis in 2001 had a significant impact on energy prices. Among the measures implemented pursuant to the emergency regulations were the pesification of prices in the Argentine MEM and the requirement that all spot prices be calculated based on the price of natural gas, even in circumstances where alternative fuel such as diesel is purchased to meet demand due to the lack of supply of natural gas.

In addition to energy payments for actual output at the prevailing spot market prices, generators would receive compensation for capacity placed at the disposal of the spot market, including stand-by capacity, additional stand-by capacity (for system capacity shortages) and ancillary services (such as frequency regulation and voltage control). Capacity payments were originally established and set in U.S. dollars to allow generators to cover their foreign-denominated costs that were not covered by the spot price. However, in 2002, the Argentine government set capacity payments in reference to the Argentine peso, thereby limiting the purpose for which capacity payments were established.

The regulatory framework governing payment for generation capacity established by the emerging regulations continued to be the same since 2002, with generators receiving compensation for available capacity at Ar$ 12 per MW until December 2010. On November 25, 2010, the Argentine Secretariat of Energy entered into an agreement with all private generators in order to increase the installed capacity during 2011. The agreement provides that the government will pay Ar$ 35 per MW-hrp (hrp stands for hours in which capacity is being paid) for available capacity of units greater than 100 MW and Ar$ 42 per MW-hrp of units smaller than 100 MW to generators that present projects to increase capacity and can provide capacity with adequate availability, as defined in the agreement. Furthermore, the remuneration to cover operation and maintenance costs will also increase from Ar$ 7.96 per MWh to Ar$ 11.96 per MWh for natural gas-based generation and from Ar$ 12.96 per MWh to Ar$ 20.96 per MWh for alternative fuel-based generation. In addition, all hydroelectric units with an installed capacity greater than 250 MW will receive 100% of their energy spot market sales. This payment system is still in effect and will remain in effect until the new regulatory model is implemented.

Seasonal Prices

The emergency regulations also made significant changes to the seasonal prices charged to distributors in the Argentine MEM, including the implementation of a cap (which varies depending on the category of customer) on the cost of electricity charged by CAMMESA to distributors at a price significantly below the spot price charged by generators. These prices have not changed since January 2005.

Pursuant to Resolution SE 1,301/2011, which announced the elimination of subsidies, the Argentine MEM’s seasonal reference prices for non-subsidized electricity were published in November 2011. This resolution also provided for the (i) discontinuation of the practice of charging subsidized prices for non-residential customers based on their payment capacity and economic activity; (ii) creation of a Register of Exceptions including a list of customers exempt from the subsidy elimination, provided that they can certify their inability to bear the seasonal reference prices for non-subsidized electricity; and (iii) the identification of the National State Subsidy, requiring CAMMESA to explicitly identify the subsidies that it provides to each level of demand. Under the resolution, distributors are also required to notify residential customers that will be affected by the elimination of subsidies.

Stabilization Fund

The stabilization fund, managed by CAMMESA, was created to absorb the difference between purchases by distributors at seasonal prices and payments to generators for energy sales at the spot price. When the spot price is lower than the seasonal price, the stabilization fund increases and when the spot price is higher than the seasonal price, the stabilization fund decreases. The outstanding balance of this fund at any given time reflects the accumulation of differences between the seasonal price and the hourly energy price in the spot market. The stabilization fund is required to maintain a minimum balance to cover payments to generators if prices in the spot market during the quarter exceed the seasonal price.

The stabilization fund has been adversely affected as a result of the modifications to the spot price and the seasonal price made by the emergency regulations, pursuant to which seasonal prices were set below spot prices resulting in large deficits in the stabilization fund. These deficits have been financed by the Argentine government through loans to CAMMESA and with FONINVEMEM funds, but these continue to be insufficient to cover the differences between the spot price and the seasonal price.

Negotiated Prices

Generators may also enter into agreements in the term market to supply energy and capacity to distributors and large customers. However, with the modifications being carried out in the generation sector, it is unclear how the generators’ role of trader will continue. Distributors are able to purchase energy through contracts on the term market instead of purchasing energy in the spot market. Term contracts typically stipulate a price based on the spot price plus a margin. Prices in the term market have at times been lower than the seasonal price that distributors are required to pay in the spot market. However, as a result of the emergency regulations, prices in the term market are currently higher than seasonal prices, particularly with respect to residential prices, making it unattractive for distributors to purchase energy under term contracts while prices remain at their current levels.

Sales by Generation Companies to Unregulated Customers

Generators may also enter into contracts in the term market to supply energy and capacity to distributors and large customers. However, with the modifications being carried out in the generation sector, it is unclear whether the generators may continue to pay the role of a trader. Distributors are able to purchase energy through contracts on the term market instead of purchasing energy in the spot market. Term contracts typically stipulate a price based on the spot price plus a margin.

As a result of the emergency regulations, prices in the term market are currently higher than seasonal prices, particularly with respect to residential tariffs, making it unattractive to distributors to purchase energy under term contracts while prices remain at their current levels.

In addition, the Argentine Secretariat of Energy issued Resolution SE 1281/2006 in September 2006. The principal objective of this resolution is to ensure that energy available in the market is used primarily to service residential customers and industrial and commercial customers whose energy demand is at or below 300 kW and who do not have access to other viable energy alternatives.

Sales to Distribution Companies and Regulated Customers

In order to stabilize the prices for distribution, the market uses the seasonal price as the energy price to be paid by distributors for their purchases of electricity traded in the spot market. This is a fixed price determined every six months by the Argentine Secretariat of Energy based on CAMMESA’s recommended seasonal price level for the next period according to its estimated spot price. CAMMESA estimates this price by evaluating its expected supply, demand and available capacity, as well as other factors. The seasonal price is maintained for at least 90 days. Since 2002, the Argentine Secretariat of Energy has been approving seasonal prices lower than those recommended by CAMMESA.

At the end of 2011, the Argentine government issued various resolutions in order to being a process of reducing subsidies to gas, electricity and water tariffs. These resolutions provide for, among other things, the (i) approval of the seasonal programming of regulated tariffs for the period from November 2011 to April 2012, (ii) establishment of a new non-subsidized seasonal price, which increased from Ar$ 243/MWh to Ar$ 320/MWh, (iii) listing of economic activities that are subject to the reduction in subsidies, (iv) creation of a register recording the exceptions to the reduction in subsidies, (v) establishment of the effective date for the new tariffs as of January 1, 2012, and (vi) provisions for voluntarily renouncing gas, electricity and water subsidies through an online system.

Specific Regulatory Charges for Electricity Companies

The authority to impose regulatory charges in Argentina is administratively divided among the federal, provincial and the municipal governments. Therefore, the tax charge varies according to where the customer lives.

Incentives and Penalties

The Energy Plus Service Program, part of the Energy Plus Program, is provided by generators that have (i) installed new generation capacity or (ii) connected previously unconnected existing generation capacity to the Argentine NIS. All “Large Customers” that had a higher demand than their Base Demand as of November 1, 2006 were required to enter into a contract with the Energy Plus Service Program to cover their excess demand. Large Customers that did not enter into such contracts are required to pay additional amounts for any consumption that exceeds the Base Demand. The prices under the contracts with Energy Plus Service Program must be approved by the relevant authorities. Unregulated customers that were unable to secure an Energy Plus Service contract are able to request CAMMESA to conduct an auction in order to satisfy their demand.

Regulation of Distribution Companies

Concessions

Distributors are companies holding a concession to distribute electricity to customers. Distributors are required to supply any and all demand of electricity in their exclusive areas of concession at tariffs and under conditions in accordance with the relevant regulations. Penalties for failing to supply the electricity demand are included in the concession agreements. Concessions are issued for distribution and retail sale, with specific terms for the concessionaire stated in the contract. The concession periods are divided into “management periods” that allow the concessionaire to give up the concession at certain intervals.

Energy Purchases

The Argentine Secretariat of Energy, through Resolution SE 1,301/2011, reduced the state subsidy on the Argentine MEM for the period from November 2011 to April 2012. This modification has been applied gradually to different segments of residential customers in order to avoid abrupt changes in billing. This process remained practically frozen from March 2012 and is only being applied to approximately 8% of customers.

By Resolution SE 2,016/2011, the Argentine Secretariat of Energy approved seasonal prices for the period from November 2012 to April 2013. The resolution sets a sole monomic price (energy and capacity) to value all purchases on the Argentine MEM by every distributor in the country and established the regulatory combining bodies and/or authorized entities that are responsible for instructing the distributors in their jurisdiction so that the distributors may correctly apply the seasonal reference prices to their respective price tables.

Distribution Tariff-Setting Process

Distribution and transmission companies have been renegotiating contracts since 2005 and although tariffs were partially and temporarily established, definitive tariffs are still pending. As a result, although the terms to define energy prices pursuant to the Argentine Electricity Act are still in force, their implementation reflects the measures taken by the authorities that reduce compensation for all electricity companies.

During 2006, our subsidiary Edesur entered into an “Agreement for Renegotiation of Concession Contract” . This agreement established, among other things, (i) a transitional tariff regime contingent on the quality of service and (ii) an Integral Rate Revision Process (“RTI”, in its Spanish acronym) to be implemented by ENRE according to Law 25,561 that would set the conditions for a new tariff regime for a five-year period. In December 2009, Edesur presented to ENRE its tariff proposal pursuant to the RTI process and also submitted support studies in accordance with the requirements established by Resolution ENRE 467/2008. This presentation only included the income requirements and did not include rate proposals, which were later presented to ENRE in May 2010. As of the date of this Report, ENRE has not defined new tariffs and the transitional tariff regime remains in effect.

Resolution 45/2010 of the Argentine Secretariat of Energy determined bonus payments to residential customers under the Energy Efficiency Program (“Puree”, in its Spanish acronym), particularly to those with a demand that is less than 1,000 kWh during a two month period. Puree was created in 2004 and established bonuses and penalties to customers depending on the level of energy savings. The net difference between the bonuses and penalties was originally deposited to the stabilization fund but this was subsequently modified at the request of Edesur and Edenor. The Argentine Secretariat of Energy authorized Edesur and Edenor to use all of such amounts to compensate for the cost variations that were not passed on to the tariffs paid by regulated customers. ENRE monitors these distribution costs with a mechanism called MCC (monitoring cost mechanism).

Edesur’s distribution tariff has been frozen since July 2008. Combined with a constant increase in costs due to inflation, this has left Edesur in a very delicate financial position. As a result, Edesur made a request in July 2012 for a special payment plan for energy purchases to CAMMESA.

In 2012, the Argentine Secretariat of Energy issued Resolution 3,787/2012 in order to facilitate financing for necessary investments to the distribution system. The resolution authorized CAMMESA to provide financing for high voltage projects in 2012 investment plan pursuant to the mechanism in Resolution 146/2002.

At the end of 2012, the ENRE issued Resolution ENRE 347/2012 titled “Trust for Financing Distribution Works” (“FOCEDE”, in its Spanish acronym). The resolution mandated the formation of a trust with funds collected from customers’ payments in order to finance necessary investments infrastructure, including any maintenance works to be carried out in the concession area. The funds collected from customers are to be differentiated depending on customer category and will be taken into consideration by the ENRE when it carries out the RTI process.

The trust contract and its operative manual agreement were signed by Edesur on November 29, 2012 and December 18, 2012, respectively.

Extraordinary penalties

ENRE published Resolution 336/2012 on November 19, 2012 to impose extraordinary penalties on Edesur for the blackouts in Edesur’s concession area between October 29, 2012 and November 14, 2012 (including the blackouts caused by a major high voltage event in the capital on November 7, 2012 and the very heavy storms on October 29 and November 9, 2012). As part of the penalties, Edesur must provide credits to the customers affected by the blackouts. These penalties are estimated to be approximately Ar$ 51.4 million for Edesur.

Regulation in Transmission

The transmission sector is regulated based on the principles established in Law 24,065 and the terms of the concession granted to Transener S.A. under Decree 2,743/92. Due to technological reasons, the transmission sector is heavily affected by economies of scale that limits competition. As a result, the transmission sector operates under monopoly conditions and is subject to considerable regulation.

Natural Gas Market

Since the economic emergency measures of 2002, the lack of investment in natural gas production forced the system to burn increasing amounts of liquid fuels.

The Argentine government has adopted different measures to improve the natural gas supply. Since 2004, local gas producers and the Argentine government have entered into various agreements to guarantee gas supply. The last agreement was signed in July 2009 and resulted in a 30% increase of the natural gas price for power generators until December 2009. In addition, Argentina and Bolivia entered into a 20-year agreement in 2006 that guarantees Argentina’s right to receive up to 28 million cubic meters of natural gas on a daily basis.

The Electronic Gas Market (“MEG”, in its Spanish acronym) was also recently created to increase the transparency of physical and commercial operations in the spot market.

Electricity Exports and Imports

In order to give priority to the internal market supply, the Argentine Secretariat of Energy adopted additional measures that restricted electricity and gas exports. Resolution SE 949/2004 established measures that allowed agents to export and import electricity under very restricted conditions. These measures prevented generators from satisfying their export commitments.

The Argentine Secretariat of Energy published Disposition 27/2004, together with related resolutions and decrees, which created a plan to ration natural gas exports and the use of transport capacity. These measures restricted gas delivery to Chile and Brazil. These restrictions are expected to continue as Resolution Enargas 1,410, which was issued in October 2010, reinforced such restrictions on gas distribution to certain customers. Specifically, the resolution mandated that the distribution of gas be made in the following order, from highest to lowest priority: (i) residential and commercial customers, (ii) the Compressed Natural Gas market, (iii) large customers, (iv) thermal generator units, and (v) exports.

Environmental Regulation

Electricity facilities are subject to federal and local environmental laws and regulations, including Law 24,051 (“Hazardous Waste Law ”) and its ancillary regulations.

Certain reporting and monitoring obligations and emission standards are imposed on the electricity sector. Failure to satisfy these requirements entitles the Argentine government to impose penalties such as suspension of operations which, in case of public services, could result in the cancellation of concessions.

Law 26,190, enacted in 2007, defined the use of non -conventional renewable energy for electricity production as a national interest and set as a target 8% market share for generation from renewable energies within a term of 10 years. During 2009, the government took actions to reach this objective by publishing Resolution 712/ 2009 and launching an international auction to promote the installation of up to 1,000 MW of renewable energy capacity. This resolution created a mechanism to sell renewable energy

through fifteen-year contracts with CAMMESA under special price conditions through ENARSA. In June 2010, the “GENREN program” awarded a total of 895 MW, distributed in the following manner: 754 MW of wind power, 110 MW of bio-fuels, 11 MW of mini-hydro, and 20 MW of solar units. The prices awarded vary from US$ 150/MWh (for mini-hydro units) to US$ 598/MWh (for solar units). In 2011, the Argentine Secretariat of Energy issued Resolution 108/11 which allowed CAMMESA to sign contracts directly with generators of renewable energy on conditions similar to Resolution 712/ 2009.

Brazil

Industry Overview

Industry Structure

Brazil’s electricity industry is organized into one large interconnected electricity system, the Brazilian NIS, which comprises most of the regions of Brazil, and several other small isolated systems.

The following chart shows the relationships among the various actors in the Brazilian NIS:

LOGO

Generation, transmission, distribution and trading are legally separated activities in Brazil.

The generation sector is organized on a competitive basis, with independent generators selling their output through private contracts with distributors, traders or unregulated customers. Differences are sold on the short-term market or spot market at the Settlement Price for the Differences (“PLD”, in its Portuguese acronym) and there is also a special mechanism between generators that seeks to re-allocate hydrological risk by offsetting differences between generators’ assured energy and that which is actually produced, called the “Electricity Re-allocation Mechanism” (“MRE”, in its Portuguese acronym).

The Brazilian Constitution was amended in 1995 to authorize foreign investment in power generation. Before, all generation concessions were held either by Brazilian individuals or entities controlled by Brazilian individuals or the Brazilian government.

The transmission sector operates under monopoly conditions. Revenues from the transmission companies are fixed by the Brazilian government. This applies to all electricity companies with transmission operations in Brazil. The transmission revenue fee is fixed and, therefore, transmission revenues do not depend on the amount of electricity transmitted.

Distribution is a public service that works under monopoly conditions and is provided by companies who have also been granted concessions. Distributors in the Brazilian NIS are not permitted to: (i) develop activities related to the generation or transmission of electricity; (ii) sell electricity to unregulated customers, except for those in their concession area and under the same conditions and tariffs maintained with respect to captive customers in the Regulated Market; (iii) hold, directly or indirectly, any interest in any other company, corporation or partnership; or (iv) develop activities that are unrelated to their respective concessions, except for those permitted by law or in the relevant concession agreement. Similarly, generators are not allowed to hold equity interests in excess of 10.0% in distributors.

The selling of electricity is governed by Law 10,848/ 2004 and Decrees 5,163/2004 and 5,177/2004 of the Electricity Trading Chamber or Clearing House (“CCEE”, in its Portuguese acronym), and ANEEL Resolution 109/2004, which introduced the Electricity Trading Convention. This is a convention in which the terms, rules and procedures of the trading in the CCEE are defined. Two possible situations were introduced by these regulations for the execution of energy sales agreements: (i) the regulated contracting environment, in which energy generation and distribution agents participate, and (ii) the free market contracting environment, in which energy generation, trading, importing and exporting agents, and unregulated customers, participate.

Commercial relations between the agents participating in the CCEE are governed mainly by energy sales agreements. All the agreements between the agents in the Brazilian NIS should be registered with the CCEE. The register includes the amounts of energy and the term. The energy prices agreed are not registered with the CCEE, but instead are specified by the parties involved in the agreements.

The CCEE books the differences between energy produced or consumed and the contracted amount. The positive or negative differences are settled in the short-term market and priced at the PLD, determined weekly for each level of load and for each sub-market, based on the system’s marginal operating cost, within a minimum and maximum price range.

The unregulated market includes the sale of electricity between generation concessionaires, independent producers, self-producers, sellers of electricity, importers of electricity, unregulated, and special customers. It also includes contracts in place between generators and distributors until their expiration, at which point new contracts may be entered into under the terms of the new regulatory framework. According to the specifications set forth in Law No. 9,427/96, unregulated customers in Brazil are those who currently have: (i) a demand of at least 3,000 kW and choose to contract the energy supply directly with generators or retailers; or (ii) a demand in the range of 500-3,000 kW and choose to contract the energy supply directly with alternative generators or traders.

The Brazilian NIS is coordinated by the Brazilian Electricity System Operator (“ONS”, in its Portuguese acronym) and is divided into four electric sub-systems: South-East/Center-West, South, North-East and North. In addition to the Brazilian NIS, there are also the isolated systems that are not part of the Brazilian NIS. These isolated systems are generally located in the Northern and North-Eastern regions of Brazil rely solely on electricity generated from coal-fired and oil-fuelled thermal plants. According to the ONS, more than 98% of the population received electricity through the public network in 2011.

Principal Regulatory Authorities

The Brazilian Ministry of Mines and Energy (“Brazilian MME”) regulates the electricity industry and its primary role is to establish the policies, guidelines and regulations for the sector.

The Brazilian National Energy Policy Council (“CNPE”, in its Portuguese acronym) is in charge of developing the national electricity policy. Among its roles are to guide the President in the formulation of energy policies and guidelines, promote the stable and secure supply of the country’s energy resources, ensure the energy supply to the most distant places of the country, establish directives for specific programs (such as the use of natural gas, alcohol, biomass, coal and thermonuclear energy), and establish directives for the import and export of energy.

The Energy Research Company (“EPE”, in its Portuguese acronym) is an entity under the Brazilian MME. Its purpose is to provide services in the area of studies and research to support the energy sector planning.

The Brazilian Governmental Agency for Electric Energy (“ANEEL”, in its Portuguese acronym) is the entity that implements the regulatory policies, and its main responsibilities include, among others: (i) supervision of the concessions for electricity sale, generation, transmission and distribution ; (ii) enactment of regulations for the electricity sector; (iii) implementation and regulation of the exploitation of electricity resources, including the use of hydroelectricity; (iv) promotion of a bidding process for new concessions; (v) resolution of administrative disputes between electricity sector agents; and (vi) setting the criteria and methodology for determining distribution and transmission tariffs, as well as the approval of all the electricity tariffs, ensuring that customers pay a fair price for energy supplied and, at the same time, preserving the economic-financial balance of the distribution companies, so that they can provide the service to agreed quality and continuity.

The Energy Sector Monitoring Committee (“CMSE”, in its Portuguese acronym) is an entity created under the scope of the Brazilian MME and is under the Brazilian MME’s direct coordination. CSME was established to evaluate the continuity and security of the energy supply across the country. CMSE has the mandate to: (i) follow the development of the energy generation, transmission, distribution, trading, import and export activities; (ii) assess the supply and customer service as well as the security of the system; (iii) identify difficulties and obstacles that affect the supply security and regularity; and (iv) recommend proposals for preventive actions that can help preserve the supply security and service.

CCEE is a non-profit company subject to authorization, inspection and regulation by ANEEL and its main purpose is to carry out the wholesale transactions and trading of electric power within the Brazilian NIS by registering the agreements resulting from market adjustments and whose agents are gathered into four categories: generation, distribution, trading and customers.

The ONS is comprised of generation, transmission and distribution companies, and independent customers, and is responsible for the coordination and control of the generation and transmission operations of the Brazilian NIS, subject to the ANEEL’s regulation and supervision.

The Electricity Law

General

Before 1993, the power tariff was the same throughout Brazil. The dealers were entitled to a guaranteed return because the regulatory regime provided for the cost of service. Concession areas that obtained a higher return than the one guaranteed deposited the surplus in a fund from which the distributors with less than the guaranteed return withdrew the difference.

In 1993, the Brazilian electric sector was reformed through Law 8,631/93, which abolished the equalization of electricity tariffs system.

The Concessions Law 8,987 and the Power Sector Law 9,074, both enacted in 1995, intended to promote competition and attract private capital into the electricity sector. Since then, several assets owned by the Brazilian government and/or state governments have been privatized.

The Power Sector Law also introduced the concept of independent power producers, or IPPs, in order to open the electricity sector to private sector investment. IPPs are single agents, or agents acting in a consortium, who receive a concession, permit or authorization from the Brazilian government to produce electricity for sale for their own account.

Law 9,648/98 created the wholesale energy market, composed by the generation and distribution companies. Under this new law, the purchase and sale of electricity are freely negotiated.

The spot price is used to value the purchase and sale of electric power in the short term market. According to the law, the CCEE is responsible for setting electricity prices in the spot market. These prices are calculated on a marginal costs basis, modeling future operation conditions and setting a merit order curve with variable costs for thermal units and opportunity cost for hydroelectric plants, resulting in one price for each subsystem set for the week subsequent to the determination.

Pursuant to Law 10,433/02, the wholesale energy market structure came to be closely regulated and monitored by ANEEL. ANEEL is also responsible for setting wholesale energy market governance rules including measures to stimulate permanent external investment.

During 2003 and 2004, the Brazilian government established the basis for a new model for the Brazilian electricity sector through Laws 10,847 and 10,848 of March 15, 2004, and Decree 5,163 of July 30, 2004. The principal objectives of these laws and decrees were to (i) guarantee the security of the electricity supply, (ii) promote the reasonability of tariffs, and (iii) improve social integration in the Brazilian electricity sector through programs designed to provide universal access to electricity.

The new model contemplates a series of measures to be followed by the agents, such as the obligation to contract all the demand of the distributors and unregulated customers. It also defines a new methodology for calculating the physical energy guarantee for sale of generation, contracting hydroelectric and thermal generating plants in proportions that ensure the best balance between guarantee and supply cost, plus the constant monitoring of the continuity and security of supply, seeking to detect occasional imbalances between supply and demand.

In terms of the tariffs’ reasonability, the model contemplates the purchase of electricity by distributors in a regulated environment through tenders in which the principle of lowest tariff is observed. As a result, the cost of acquiring electricity to be passed on to captive customers can be reduced. The new model creates conditions for the benefits of electricity made available to customers who do not yet have this service and for guaranteeing a subsidy for low income customers.

Limits and Restrictions

Regulatory Resolution 299/2008 repeals certain sections of ANEEL Resolution 278/2000, which established the limits and conditions for the participation of electricity distributors and traders. The section of Resolution 278/2000 relating to limits on

generation remains in effect and establishes that (i) an entity cannot have more than a 20% participation in the installed capacity, (ii) an entity may not have more than a 25% participation in the installed capacity of the electricity system of the South, South East and Center West regions, and (iii) an entity may not have more than a 35% participation in the installed capacity in the North and North East regions.

Section 7 of Resolution 278/2000, which defines that a distribution-concession company may only own up to 30% of the energy required to meet their captive demand from related companies, has also been retained.

Regulation of Generation Companies

Concessions

The Concessions Law provides that, upon receiving a concession, IPPs, self-producers, suppliers and customers will have access to the distribution and transmission systems owned by other concessionaires, provided that they are reimbursed for their costs as determined by ANEEL.

Companies or consortia that intend to build or operate hydroelectric generation facilities with a capacity exceeding 30 MW or transmission networks in Brazil have to resort to a public tender process. Concessions granted to the holder give the right to generate, transmit or distribute electricity, as the case may be, in a given concession area for a certain period of time.

Concessions are limited to 35 years for new generation concessions and to 30 years for new transmission or distribution concessions. Existing concessions may be renewed at the Brazilian government’s discretion for a period equal to their initial term.

In September 2012, ANEEL published Provisional Resolution 579, which establishes the criteria for the renewal of generation, transmission and distribution concessions that expire between 2015 and 2017. It foresees the reduction of energy tariffs and indemnities for non-depreciated investments in hydroelectric plants and transmission installations. In addition, Provisional Resolution 577 defines procedures for the temporary provision of the electricity energy service in the case of cancellation of concessions due to management problems. It also reinforces the powers of ANEEL to intervene in the case of economic-financial imbalance in order to avoid affecting the service provided.

On January 23, 2013, the Brazilian Congress approved Law 12,783, which renewed electricity concessions according to Provisional Resolution 579. This law requires companies to reduce the average electricity tariff by 20.2% from February, 2013 and to extend generation, transmission and distribution concessions for up to 30 years, for both hydroelectric and thermal plants, which expire between 2015 and 2017.

Dispatch and Pricing (Settlement Price for the Differences (“PLD”))

PLD is used to value the purchase and the sale of electric power in the short term market. The price-setting process of the electric power traded in the short-term market is accomplished by using the data employed by the ONS to optimize the operation of the Brazilian NIS.

The mathematical models used to compute the PLD takes into account the preponderance of hydro-electric plants within the Brazilian power generation grid. The purpose is to find an optimal equilibrium solution between the current benefit obtained from the use of the water and the future benefit resulting from its storage, measured in terms of the savings from the use of fuels for thermal plants.

The PLD is an amount computed on a weekly basis for each load level based on the Marginal Operational Cost, which in turn is limited by a maximum and minimum price in effect for each period and submarket. The intervals set for the duration of each level are determined by the ONS for each month and reported to the CCEE to be included into the accounting and settlement system.

The model used to compute the PLD seeks to achieve an optimal result for the period being studied and to define both the hydroelectric and thermal power generation for each submarket by taking into account the hydrological conditions, the demand for electric power, the prices of fuel, the cost of the deficit, the entry of new projects into operation and the availability of equipment used for generation and transmission. As result of this process, the Marginal Operational Costs can be obtained for each load level and submarket.

The calculation of the price is based on the “ex-ante” dispatch that is determined based on estimated information existing prior to the actual operation of the system, taking into account the declared availability amounts regarding both the generation and the consumption envisaged for each submarket. The complete process for calculating the PLD involves the use of the computational models NEWAVE and DECOMP. These models are used to calculate the Marginal Operational Cost for each submarket on a monthly and weekly basis.

Electricity Re-allocation Mechanism (“MRE”)

The Electricity Re-allocation Mechanism provides financial protection against hydrological risks for hydro-generators in order to mitigate the shared hydrological risks that affect generators and assure the optimal use of the hydroelectric resources of the interconnected power system.

The mechanism guarantees that despite of the centralized dispatch all the generators that participate in the MRE will have a participation in the overall hydro generation dispatched in the proportion of its assured energy. The value of the final allocated energy to a generator can be greater or less than its assured energy depending if the overall hydro generation is greater or less than the overall hydro assured energy, respectively. This mechanism permits that each generator before buying energy in the spot market to accomplish with its contracts, be able to buy cheaper energy with price covers the incremental costs of operation and maintenance of hydroelectric plants and the payment of financial use of water compensation. The tariff used for trading energy in the MRE, the Optimum Energy Tariff , was set as R$ 10.01/MWh for 2013.

As the overall generation is more stable then the individual production, the MRE is a very efficient mechanism to reduce the volatility of the individual production and the hydrological risk.

Therefore the energy contracts are only financial instruments in the Brazilian system and generation is totally disassociated from the energy contracts.

Sales between the Agents of the Market

The current model for the electric sector states that the trading of electric power is accomplished in two market environments: the Regulated Contracting Environment (“ACR”, in its Portuguese acronym) and the Free-Market Contracting Environment (“ACL”, in its Portuguese acronym).

Contracting in the ACR is formalized by means of regulated, bilateral agreements, called Electric Power Trading Agreements within the Regulated Environment (“CCEAR”, in its Portuguese acronym) entered into between Selling Agents (sellers, generators, independent producers or self-producers) and Purchasing Agents (distributors) who participate in electric power purchase and sale auctions.

In the ACL environment, on the other hand, the negotiation among the Generating Agents, Trading Agents, Free-Market Customers, Importers and Exporters of electric power is accomplished freely, whereby the agreements for the purchase and sale of electric power are entered into through bilateral agreements.

Generation agents, regardless of whether they are public generation concessionaires, IPPs, self-producers or Trading Agents, are allowed to sell electric power within the two environments. This allows the overall market to remain competitive. All agreements that have been entered into in the ACR or the ACL are registered in the CCEE and they serve as a basis for the accounting posting and the settlement of the differences in the short term market.

Sales by Generation Companies to Unregulated Customers

In the unregulated contracting environment, the conditions for purchasing energy are negotiable between suppliers and their customers. As for the regulated environment, where distribution companies operate, the purchase of energy must be conducted pursuant to a bidding process coordinated by ANEEL. In 2012, the Brazilian MME published its Decree 455 which mandates the creation of a prices index and a requirement to register energy contracts ex-ante. According to the internal schedule of the CCEE, the new price index is expected to be published on or around January 2014. It is expected that this index will be subject to internal tests over a six month period before being officially published in the market.

Sales by Distribution Companies and Regulated Customers

Pursuant to market regulations, 100% of the energy demand from distributors must be satisfied through long-term contracts. Contracts must be renewed or newly entered into prior to the expiration of current contracts.

Tenders under the current regulatory environment are as follows: (i) Tenders A-5, corresponding to tenders for energy purchases from new generation sources to be supplied five years following the tender; (ii) Tenders A-3, for the acquisition of energy from new

generation sources; (iii) Tenders A- 1, for the acquisition of energy from existing generation sources; and (iv) adjustment tenders, for supplementing the energy load necessary for servicing customers in the distribution concession market, with a limit of 1% of such load. Reserve tenders are also carried out for increasing the security of the system.

Various energy tenders were held during 2011, including a Tender A-3 and a reserve tender completed in August and a Tender A-5 in December.

In the A-3 tender process for the supply of 2014, 2,744.6 MW of new capacity was assigned and is to be generated by 51 plants. Of the total contracted, 62% was from renewable sources (hydroelectric, wind and biomass) and the remaining 38% from fossil fuels (natural gas).

The tender for reserve energy in August 2011 assigned 1,218.1 MW. These were from wind farm, thermal and biomass projects, involving a total of 41 generating plants. The average price was R$ 99.61/MWh.

For the new A-5 tender process carried out in December 2011, 42 projects were assigned with a capacity of 1,211.5 MW at an average price of R$ 102.18/MWh.

For 2012, two tenders were planned. A Tender A-3 for December 12, 2012 was cancelled due to the low demand of distributors. A Tender A-5 for new energy was held on December 14, 2012. Of the 574.3 MW of total installed capacity up for tender, 303.5 MW was allocated. The weighted average price was fixed in R$ 91.25/MWh. Of the total energy allocated, 294.2 MW was allocated to two hydroelectric plants (at an average price of R$ 93.46/MWh) and 281.9 MW was allocated to ten wind farms (at an average price of R$ 87.94/MWh) .

Sales of Capacity to Other Generation Companies

Generators can sell their energy to other generators through direct negotiation at freely-agreed prices and conditions.

Incentives and Penalties

Another change imposed on the electricity sector is the separation of the bidding process for “existing power” and “new power” projects. The Brazilian government believes that a “new power project” needs more favorable contractual conditions such as long term power purchase agreements (15 years for thermal and 30 years for hydro) and certain price levels for each technology in order to promote investment for the required expansion. On the other hand, “existing power,” which includes depreciated power plants, can sell their energy at lower prices under contracts with shorter terms.

Law 10,438/02 created certain incentive programs for the use of alternative sources in the generation of electricity, known under the name of Proinfa. It assures the purchase of the electricity generated by Eletrobras for a period of 20 years and financial support from the Banco Nacional do Desenvolvimento, or BNDES, a state-owned development bank. Other programs include a discount of up to 50% on the distribution or transmission tariffs and a special exception for the customers with electricity demand in the range of 500-3,000 kW who decide to migrate to an unregulated environment, provided that such customers purchase electricity from generating companies using non-conventional sources of electricity.

Selling agents are responsible to pay the buying agent if they are unable to satisfy their delivery obligations. ANEEL regulations set forth the fines applicable to electricity agents based on the nature and the materiality of the violation (including warnings, fines, temporary suspension of the right to participate in bids for new concessions, licenses or authorizations and forfeiture). For each violation, fines may be imposed for up to 2% of the concessionaire’s revenues arising from the sale of electricity and services provided (net of taxes) in the 12-month period immediately preceding any assessment notice.

ANEEL may also impose restrictions on the terms and conditions of agreements between related parties and, under extreme circumstances, terminate such agreements.

Decree 5,163/2004 establishes that the selling agents must assure 100% physical coverage for their energy and power contracts. This coverage must be made up of physical guarantees from its own power plants or through the purchase of energy or power contracts from third parties.

Among other aspects, ANEEL’s Normative Resolution 109/2004 specifies that when these limits are not met, the generation companies and traders are subject to financial penalties. The determination of penalties is predicated on a 12-month period and the revenues obtained from the levying of the penalties are reverted to tariff modality within the ACR.

If the limits on contracting and physical coverage defined in the Trading Rules are not met, the relevant generation companies and traders are notified by the Superintendent of CCEE. Pursuant to the specific Trading Procedure, CCEE’s agents are allowed to file an appeal to be evaluated by CCEE’s Board of Directors who then decides whether to collect or to cancel the financial penalty.

Generation agents may sell power through contracts signed within the ACR or the ACL. Public Service Generators and IPPs must provide a physical coverage from their own power generation for 100% of their sales contracts. Self-producers generate energy for their own exclusive use and they may sell excess power through contracts with ANEEL’s authorization. In both cases, the verification of physical coverage is accomplished on a monthly basis, predicated on generation data and on sales contracts for the last 12 months. Generation agents must pay penalties if they fail to provide physical coverage.

Regulation of Distribution Companies

Energy Purchases

In the regulated market, electricity distribution companies buy electricity through bids that are regulated by ANEEL and organized by CCEE. Distributors must buy electricity at public bids.

There are three types of regulated bids: new energy bids, existing energy bids and adjustment bids. The government also has the right to call special bids for renewable electricity (biomass, mini-hydro, solar and wind power). ANEEL and CCEE hold the bids annually. The contracting system is multilateral, with generating companies entering into contracts with all distributors who call for bids.

Distribution Tariffs to Final Customers

Distribution tariff rates to final customers are subject to review by ANEEL, which has the authority to adjust and review these tariffs in response to changes in energy purchase costs and market conditions.

Distribution Tariff-Setting Process

When adjusting distribution tariffs, ANEEL divides the Annual Reference Value, the costs of distribution companies, into: (i) costs that are beyond the control of the distributor (“Parcel A costs”), and (ii) costs that are under control of distributors (“Parcel B costs”), the Value-Added Distribution. Each distribution company’s concession agreement provides for an annual adjustment.

The Concessions Law establishes three kinds of reviews for final customer tariffs: annual tariff resetting, and both ordinary and extraordinary tariff reviews.

Distribution companies’ pricing is intended to maintain constant concessionaire operating margins by allowing for tariff gains due to Parcel A costs and by permitting the concessionaire to retain any efficiency gains achieved for defined periods of time. Tariffs to end customers are also adjusted according to the variation of costs incurred in purchasing electricity.

Ordinary tariff reviews take into account the entire tariff-setting structure for the company, including the costs of providing services and purchasing energy, as well as a return for the investor. The tariff review period is defined by distributors at the time of signing their respective Concession Agreement. Therefore, in Brazil, some distributors have a period of three years while most have four year periods and some have five year periods. This means the tariff review applies to all distributors, but with different time periods. Under their concessions, Coelce and Ampla are subject to tariff reviews every four and five years, respectively.

Under the previous methodology, the asset base for calculating an allowed return for the investor is the market replacement value depreciated during its accounting useful life, and the rate of return allowed for those assets is based on the weighted average cost of capital, or WACC, for a “model company.” The operating and maintenance costs reflected in the tariff are calculated based on the model company, which considers the special characteristics of each distribution concession area.

In November 2011, ANEEL approved a new methodology relating to the rules for the third cycle of periodic tariff revisions for electricity tariffs, effective from 2011 to 2014. There were significant changes with respect to the previous methodology:

•

For operating costs, the model company is no longer used. The values defined in the previous cycle are adjusted by the variation in the number of customers, consumption and networks, discounting the productivity gains achieved by the distributors;

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The WACC rate of return was reduced to reflect the lower risk of investing;

•

The sharing of other revenues with the customer was expanded;

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A new methodology to estimate the distribution of productivity gains and to maintain the economic and financial balance over the tariff cycle was adopted;

•

A new incentive mechanism for improving the quality of service was introduced.

The law guarantees an economic and financial equilibrium for a company in the event that there is a substantial change in its operating costs. In the event that the Parcel A cost components, such as energy purchases and taxes, increases significantly within the period between two annual tariff adjustments, the concessionaire may request from ANEEL a pass-through of those costs to the final customers.

An annual tariff adjustment applicable to Ampla was introduced on March 15, 2012, with an average 6.68%, resulted of a change in inflation, energy costs, in addition to the sector charges and subsidies that are in the rate.

Ordinary tariff reviews should have been introduced for Coelce in 2011. However, its rates were kept unchanged due to the uncertainty, in April 2011, of the new methodology to be applied. With the publication of the new methodology, Coelce had, in April 2012, in addition to the annual adjustment, a tariff review retroactive to April 2011.

In April 2012, ANEEL approved the annual tariff resetting and the ordinary tariff review of Coelce. Reviews result in a negative average adjustment of 12.2% due to the ordinary tariff review and an annual positive adjustment of 5.21% due to the annual tariff resetting, providing an average reduction of 7.61% for all customers after April 22, 2012.

For Coelce’s tariff review were pending the ruling of the court regarding the application by ANEEL of fiscal incentives granted to the companies in the area of SUDENE (Superintendency of the Development of Northeast), reducing the WACC rate of return for Coelce and reducing tariffs for final customers. In June 2012, ANEEL approved the new tariffs considering the application of fiscal incentives granted to companies in that area. Therefore, the average reduction in customers’ tariffs changed to a negative variation of 6.76%. This means an increase of 0.85%, which impacts in higher revenues of about US$ 7 million from July 2012 to December 2012.

Governmental Tariff Reduction Plan (Provisional Resolution 579/2012)

On September 12, 2012, the Brazilian government published Provisional Resolution 579/2012, which intends to reduce the tariff for final clients and to define new concession’s renewal politics for generation companies.

In order to reduce the tariff, the Brazilian government proposed to eliminate two sector charges, the RGR or Global Reversal Reserve, which are funds to promote expansion in the electricity sector and to indemnify concessions, and the CCC or Fuel Consumption Bill, which is a subsidy to thermal generation companies mainly in the Northern region. It also reduce by a 75% the CDE or Energetic Development Account, which provide the energetic development from alternative sources, promote energy service globalization, and subsidize the low income residential sub-class. These charges will be covered directly with funds of the Brazilian Government.

In addition, this resolution provides new concession’s renewal politics for generation companies, which concession contracts expire until 2017 (20% of the generation companies). Although existing laws provided for the possibility of renewing such concessions, there was no clear guidance on the terms of the renewed concessions. With the new polity charges of energy purchases will be reduced due to the non-recognition of assets already amortized, and therefore if the concession-holders choose to renew under such terms, then they would only be able to recuperate costs related to operation and maintenance.

Legislation containing Provisional Resolution 579/2012 was approved by the Brazilian House of Representatives and was sent for signature of the President of Brazil, by the Law 12.783/2013. The tariff reduction plan, which is expected to approximately reduce tariffs to be passed on to customers by 20%, was passed on January 24, 2013 after an extraordinary tariff review.

Regulation in Transmission

Transmission lines in Brazil are usually very long, since most hydroelectric plants are usually located away from the large centers of power consumption. Today, the country’s system is almost entirely interconnected. Only the states of Amazonas, Roraima, Acre, Amapá, Rondônia and a part of Pará are still not linked up to the Interconnected power system. In these states, supply is carried out by small thermal plants or hydroelectric plants located close to their respective capital cities, but the Brazilian government is gradually connecting these areas.

The interconnected power system provides for the exchange of power among the different regions when any region faces problems generating hydroelectric power due to a drop in its reservoir levels. As the rainy seasons are different in the south, southeast, north and northeast of Brazil, the higher voltage transmission lines (500 kV or 750 kV) make it possible for locations with insufficient power output to be supplied by generating centers that are in a more favorable location.

Any electric power market agent that produces or consumes power is entitled to use the Basic Network. Free-market customers also have this right, provided that they comply with certain technical and legal requirements. This is called free access and is guaranteed by law and by ANEEL.

The operation and management of the Basic Network is the responsibility of ONS, which is also responsible for managing energy dispatched from plants in optimized conditions, involving use of the interconnected power system hydroelectric reservoirs and thermal plants’ fuel.

Environmental Regulation

The Brazilian Constitution gives the federal, state and local governments power to enact laws designed to protect the environment, and to issue regulations under such laws. While the Brazilian government is empowered to enact environmental regulations, the state governments are usually more stringent. Most of the environmental regulations in Brazil are at the state and local level rather than at the federal level.

Hydroelectric facilities are required to obtain concessions for water rights and environmental approvals. Thermal electricity generation, transmission and distribution companies are required to obtain environmental approvals from environmental regulatory authorities.

Colombia

Industry Overview

Industry Structure

The Wholesale Electricity Market in Colombia ( “Colombian MEM”, in its Spanish acronym) is based on a competitive market model and operates under open access principles. The Colombian government participates in this market through an institutional structure that is responsible for setting forth policies and regulations, as well as for exercising supervision and control powers in respect of market participants. The Colombian MEM relies for its effective operation on a central agency known as the Colombian Administrator of the Commercial Exchange System (“ASIC”, in its Spanish acronym).

The Colombian National Interconnected Electric System (“Colombian NIS”) includes generation plants, the interconnection grid, regional transmission lines, distribution lines and end-customers.

There are two categories of agents, generators and traders, who are allowed to buy and sell electricity as well as related products in the Colombian MEM. All of the electricity supply offered by generation companies connected to the Colombian NIS and all of the electricity requirements of end-customers, whose demand is represented by trading companies, are traded on the Colombian MEM.

The following chart shows the relationships among the various actors in the Colombian MEM:

LOGO

Generation activity consists of the production of electricity through hydroelectric, thermoelectric and all other generation plants connected to the Colombian NIS. The generation sector is organized on a competitive basis, with independent generators selling their output on the spot market or through private contracts with large customers. Generation companies are required to participate in the Colombian MEM with all of their generation plants or units connected to the Colombian NIS with generating capacities equivalent to or exceeding 20 MW. Generation companies declare their energy availability and the price at which they are willing to sell it. This electricity is centrally dispatched by the National Dispatch Center (“CND”, in its Spanish acronym).

Trading consists of intermediation between the players that provide electricity generation, transmission and distribution services and the customers of these services, whether or not that activity is carried out together with other electricity-sector activities.

Electricity transactions in the Colombian MEM are carried out under the three following modes:

1. Energy spot market: short term daily market

2. Bilateral contracts: long term market; and

3. “Firm Energy” .

“Firm Energy” refers to the maximum electric energy that a generation plant is able to deliver on a continual basis during a year, in extreme conditions of hydro inflows. The generator who acquires a Firm Energy Commitment (“OEF”, in its Spanish acronym) will receive a fixed remuneration during the commitment period, which is explained in the “Incentives and Penalties” section below.

Transmission works under monopoly conditions and with a guaranteed annual fixed income that is determined by the new replacement value of the networks and equipment and by the resulting value of bidding processes awarding new projects for the expansion of the National Transmission System (“NTS”). This value is allocated among the traders of the NTS in proportion to their energy demand.

Distribution is defined as the operation of local networks below 220 kV. Any customer may have access to a distribution network for which it pays a connection charge.

There is one interconnected system, the Colombian NIS, and several isolated regional and smaller systems that provide electricity to specific areas. According to the World Energy Council 93.6% of the Colombian population in 2012 received electricity through the public network.

Principal Regulatory Authorities

The Colombian Ministry of Mines and Energy (“Colombian MME”) is responsible for the policy-making of the electricity sector, which aims for a better use of the mining and energy resources available in Colombia, and in turn contributes to the country’s social and economic development.

The Colombian Mining and Energy Planning Agency (“UPME”, in its Spanish acronym) is in charge of planning the expansion of the generation and transmission networks.

The National Council for Economic and Social Policy (“CONPES”, in its Spanish acronym) is the highest national planning authority and works as an advisory entity to the government in all aspects related to the Colombia’s economic and social development. It coordinates and directs the entities responsible for economic and social direction, through the study and approval of documents on policy development.

The National Planning Department (“DNP”, in its Spanish acronym) performs the functions of Executive Secretariat of the CONPES and is therefore the entity responsible for coordinating and presenting the documents for discussion at meetings.

The Energy and Gas Regulatory Commission (“CREG”, in its Spanish acronym) implements the principles of the industry set out by the Colombian Electricity Act. This commission is constituted by five experts named by the Colombian President, the Colombian MME, the Colombian Ministry of Public Credit and the director of the DNP or their delegates. Such principles are: efficiency (the correct allocation and use of resources and the supply of electricity at minimum cost); quality (compliance with technical requirements); continuity (continuous electricity supply without unjustified interruptions); adaptability (the incorporation of modern technology and administrative systems to promote quality and efficiency); neutrality (impartial treatment of all electricity customers); solidarity (the provision of funds by high-income customers to subsidize the subsistence consumption of low-income customers); and fairness (an adequate and nondiscriminatory supply of electricity to all regions and sectors of the country).

CREG is empowered to issue regulations that govern technical and commercial operations and to set charges for regulated activities. CREG’s main functions are to establish conditions for gradual deregulation of the electricity sector toward an open and competitive market, approve charges for transmission and distribution networks and for regulated customers, establish the methodology for calculating maximum tariffs for supplying the regulated market, regulations for planning and coordination of operations of the Colombian NIS, technical requirements for quality, reliability and security of supply, and protection of customers’ rights.

The National Operation Council (“CNO”, in its Spanish acronym) is responsible for establishing technical standards to facilitate the efficient integration and operation of the Colombian NIS. It is a consultative entity composed of the CND’s Director and generation, transmission and distribution company representatives.

The Commercialization Advisory Committee (“CAC”) is an advisory entity which assists CREG with the commercial aspects of the Colombian MEM.

The Superintendency of Industry and Commerce investigates, corrects and sanctions restrictive commercial competition practices, such as antitrust behavior. It also oversees mergers of companies operating in the same productive activities to prevent excessive concentration or monopoly of certain industries.

The Superintendency of Domestic Public Services (“SSPD”, in its Spanish acronym) is responsible for overseeing all public utility services companies. The SSPD monitors the efficiency of all utility companies and the quality of services. The SSPD can also assume control over utility companies when the availability of utility services or the viability of such companies is at risk. Other duties include (i) enforcing regulations, imposing penalties and generally overseeing the financial and administrative performance of public utility companies, (ii) providing accounting norms and rules for public service companies, and (iii) in general, organizing information networks and databases pertaining to public utilities.

The Electricity Law

General

In 1994, the Colombian Congress passed significant reforms affecting the public utilities industry. These reforms, contained in Law 142, known as the Public Utility Services Law (“LSPD”, in its Spanish acronym), and Law 143, were the result of constitutional amendments made in 1991. These laws form the basic legal framework that currently governs the electricity sector in Colombia. The most significant reforms included the opening of the electricity industry to private sector participation, the functional segregation of

the electricity sector into four distinct activities (generation, transmission, distribution and trading), the creation of an open and competitive wholesale electricity market, the regulation of transmission and distribution activities as regulated monopolies and the adoption of universal access principles applicable to transmission and distribution networks.

The Colombian Electricity Act regulates electricity generation, trading, transmission, and distribution (collectively, the “Activities”). Under the law, any company existing before 1994, domestic or foreign, may undertake any of the Activities. Companies established subsequent to such date can engage exclusively in only one of such Activities. Trading, however, can be combined with either generation or distribution.

Limits and Restrictions

The market share for generators and traders is limited. The limit for generators is 25% of the Colombian system’s Firm Energy. The principal market share metric used by CREG to regulate the generation market is the percentage of Firm Energy that a market participant holds.

Additionally, if an electricity generation company’s share of Colombia’s total Firm Energy ranges from 25% to 30% and the market’s Herfindahl Hirschman Index (“IHH”, in its Spanish acronym), a measure of market concentration, is at least 1,800, such company becomes subject to monitoring by the SSPD. If an electricity generation company’s share of Colombia’s total Firm Energy exceeds 30%, such company may be required to sell its share exceeding the 25% threshold.

Similarly, a trader may not account for more than 25% of the trading activity in the Colombian NIS. Limitations for traders take into account international energy sales. Market share is calculated on a monthly basis according to the trader’s commercial demand and traders have up to six months to reduce their market share when the limit is exceeded.

Such limits are applied to economic groups, including companies that are controlled by, or under common control with, other companies. In addition, generators may not own more than a 25% interest in a distributor, and vice versa. However, this limitation only applies to individual companies and does not preclude cross-ownership by companies within the same corporate group.

A distribution company can have more than 25% of an integrated company’s equity if the market share of the latter company is less than 2% of the national generation business. A company created before the enactment of Law 143 is prohibited from merging with another company created after Law 143 came into effect.

A generator, distributor, trader or an integrated company (i.e., a firm combining generation, transmission and distribution activities) cannot own more than 15% of the equity in a transmission company if the latter represents more than 2% of the national transmission business in terms of revenues.

Regulation of Generation Companies

Concessions

The Colombian electricity sector was structurally reformed by Laws 142 and 143 of 1994. Under this new legal structure, economic activities related to the provision of the electricity service are governed by the constitutional principles of free market economic activity, free market private initiative, freedom to enter and leave, corporate freedom, free market competition and private property, with regulation and inspection, surveillance and control by the state.

According to Law 143 of 1994, these constitutional principles of freedom are the general rule in the electricity sector business, while the concession is the exception. Different economic, public, private or mixed agents may participate in the sector’s activities, which agents shall enjoy the freedom to develop their functions in a context of free market competition. In order to operate or start up projects, they must obtain from the competent authorities the necessary environmental, sanitation and water-right permits as well as other municipal permits and licenses. All economic agents may construct generation plants and their respective connection lines to the interconnection and transmission networks.

The Colombian government cannot legally participate in the execution and exploitation of generation projects. As a general rule, such projects are to be carried out by the private sector. The Colombian government is only authorized to sign concession agreements relating to generation when there is no entity prepared to assume these activities on comparable conditions.

Dispatch and Pricing

The purchase and sale of electricity can take place between generators, distributors acting in their capacity as traders, traders (who do not generate or distribute electricity) and unregulated customers. There are no restrictions for new entrants into the market as long as the participants comply with the applicable laws and regulations.

The Colombian MEM facilitates the sale of excess energy that has not been committed under contracts. In the wholesale market, an hourly spot price for all dispatched units is established based on the offer price of the highest priced energy dispatched unit for that period. The CND receives price bids each day from all the generators participating in the Colombian MEM. These bids indicate prices and the hourly available capacity for the following day. Based on this information, the CND, guided by an “optimal dispatch” principle (which assumes an infinite transmission capacity through the network), ranks the dispatch optimized during the 24-hour period, taking into account initial operating conditions, and determining which generators will be dispatched the following day in order to satisfy expected demand. The price for all generators is set as the most expensive generator dispatched in each hourly period under the optimal dispatch. This price-ranking system is intended to ensure that national demand, increased by the total amount of energy exported to other countries, will be satisfied at the lowest cost combination of available generating units in the country.

Additionally, the CND plans for the dispatch, which takes into account the limitations of the network, as well as other conditions necessary to satisfy the energy demand expected for the following day in a safe, reliable and cost-efficient manner. The cost differences between the “planned dispatch” and the “optimal dispatch” are called “restriction costs.” The net value of such restriction costs is assigned proportionally to all the traders within the Colombian NIS, according to their energy demand, and these costs are passed through to the end customers. Some generators have initiated legal proceedings against the government arguing that recognized prices do not fully cover the costs associated with these restrictions on the grounds that current regulations do not take into account all the costs incurred under safely reliable generation. However, from CREG’s point of view, Resolution 036 of 2010 modified the remuneration of these restrictions for hydro plants by assigning the opportunity cost to the spot price.

In July 2012, CREG published Resolution 076-2012 (“Statute for situations of scarcity in the MEM as part of the operative regulations”) that proposed a draft resolution for defining the rules of operation under critical supply conditions . The deadline for consultations was extended and the project was republished in December 2012 according to Resolution 150-2012. The new deadline to submit comments or observations was February 18, 2013 but the final publication date is still unknown. The proposal is essentially a market intervention scheme that seeks to ensure the care of the demand in critical situations.

Sales by Generation Companies to Unregulated Customers

In the unregulated market, generation companies and unregulated customers sign contracts in which terms and prices are freely agreed. Typically, these agreements establish that the customer pays the energy that it consumes each month without a cap or a floor. The prices are fixed in Colombian pesos indexed monthly to the Colombian PPI. According to resolution CREG 131 of 1998, to be considered “unregulated,” customers are required to have an average monthly power demand for six months of at least 0.1 MW, or a minimum of 55 MWh in monthly average energy demand over the prior six months.

Sales by Distribution Companies to Regulated Customers

The regulated market is served by traders and by distributors acting as traders, who bill all service costs, according to prices regulated by CREG. The scheme allows distributors to pass through the average purchase price of all the market transactions that affect the regulated market into the clients’ tariff, thereby mitigating spot price volatility and providing an efficiency signal to the market. Additionally, CREG established a formula for the total cost of service, which transfers transmission, distribution, marketing costs, and physical losses costs to the regulated market.

Sales by Generation Companies to Traders for the Regulated market

Traders in the regulated market are required to buy energy through procedures that ensure free market competition. For evaluating the bids, the buyer takes into account price factors as well as other technical conditions and commercial objectives to be defined before the contracting process. These agreements can be signed with different terms, such as: “Pay amount contracted,” “Pay amount demanded with or without a limit,” “Pay the percentage actually consumed,” etc. Prices are denominated in Colombian pesos indexed monthly to the Colombian CPI.

Sales to Other Generation Companies

Generators can sell their energy to other generators through direct negotiation, at freely negotiated prices and conditions.

Regulatory Charges

Contribution by generation per Law 99 of 1993: Generation companies are obliged to pay monthly payments based on their generation to the regional autonomous corporations for environmental protection in areas where the plants are located and to the municipalities where the generation plants are situated. For more information, see “— Environmental Regulation” below.

Generation contribution to the Financial Support Fund for Energy for Unconnected Zones (“FAZNI”, in its Spanish acronym): Law 633 of 2000 (tax reform) states that generators must make a contribution of CP 1 to the FAZNI for every kilowatt dispatched on the Wholesale Energy Exchange. Initially, this requirement was effective until December 31, 2007 but it was extended to 2014 by Law 2,099 of November 2006.

Incentives and Penalties

Generators connected to the Colombian NIS can also receive “reliability payments” which are a result of the OEF that they provide to the system. The OEF is a commitment on the part of generation companies backed by its physical resource capable of producing firm energy during scarcity periods. The generator that acquires an OEF will receive a fixed compensation during the commitment period, whether or not the fulfillment of its obligation is required. To receive reliability payments, generators have to participate in firm energy bids by declaring and certifying such firm energy. Until November 2012, the transition period, the firm energy supply for reliability purposes was assigned proportionally to the declared firm energy of each generator. Beyond the transition period, the additional firm energy required by the system is allocated by bids.

During 2011, CREG published resolutions for the assignment of OEF for the periods from December 2014 to November 2015 and from December 2015 to November 2016. For the first of these periods, the OEF assigned this pro rata to the existing generators while, for the second, it carried out a second tender for the electricity sector on December 27, 2011. The new resolutions include incentives for thermal plants that back up their OEF with imported natural gas to guarantee its OEF for 10 years, from December 2014.

The tender for firm energy for the period from November 2015 to December 2016 was made on December 27, 2011. Seven companies participated with a total of eight projects of which five were assigned at a price of US$ 15.7/MWh. The new projects are Río Ambeima (hydro, 45 MW), Carlos Lleras Restrepo (hydro, 78 MW), San Miguel (hydro, 42 MW), Gecelca 32 (thermal, 250 MW) and Tasajero 2 (thermal, 160 MW). The new assignments were made for a period of twenty years as of December 1, 2015.

In addition, on January 26, 2012, the auction was concluded for projects with long construction periods (“GPPS”, in its Spanish acronym) which assigned OEFs for a period of twenty years to three hydroelectric projects and one thermal project. Two of these were assigned to new plants : Termonorte which will have a capacity of 88 MW by 2017 and the Porvenir II hydroelectric power plant which will have a capacity of 352 MW by 2018. The other two involved increases in OEF for plants already under construction and had available firm energy following the GPPS process carried out in 2008 (Sogamoso and Pescadero-Ituango hydroelectric plants). The process ended with assignment prices below the maximum defined for the auction in December (US$ 15.7/MWh), and were in connection with Termonorte (US$ 14.9/MWh); Porvenir II (US$ 11.7/MWh); Sogamoso and Pescadero-Ituango (US$ 15.7/MWh).

CREG regulated the reconfiguration auction scheme, under the methodology of reliability charge that allowed agents to change the beginning of the OEF by renouncing the “reliability payments” and paying a premium. XM published the results of the auction sale reconfiguration of OEF and Termocol, Amoya and Gecelca were the participating companies.

During 2012 CREG also issued the statement regarding OEF allocation for the period from December 2016 to November 2017. CREG indicated that (i) a tender for OEF allocation was not necessary due to the conditions of the system and (ii) the assignment schedule will be published once there is greater certainty with regards the dates for execution of the Colombia-Panama interconnection agreement and the processes for importing natural gas. CREG’s Circular 045 states that this publication will be made after June 30, 2014.

Despite such statement, a tender was finalized in July 2012 for the reconfiguration of the OEF for the period from December 2012 to November 2013. The OEF was allocated to Termocol, which owns the Poliobras project (4.5 GWh per day) and to Amoyá, which owns the Isagen project (0.5 GWh per day). Such tenders are called when previously allocated OEFs exceed the projected demand for a certain period. The tender ended with a price margin of US$ 0.6 per MWh, which is over the reliability load price for the period from December 2012 to November 2013.

Electricity Exports and Imports

Decision CAN 536 of 2002, CAN 720 of 2009, and CAN 757 of 2011, signed by the countries that participate in the Andean Nations Community (“CAN”, in its Spanish acronym), Colombia, Ecuador, Bolivia and Peru, established the general framework for the interconnection of electrical systems that created a coordinated economic dispatch for the countries involved in the interconnections. Under this framework, the interconnection system between Colombia and Ecuador was inaugurated in March 2003. The two countries adopted a transitional regime pursuant to CAN 757, while adopting common standards in order to make such international transactions viable.

In addition to the interconnection with Ecuador Colombia is also interconnected with Venezuela by three links, the most important being the Cuestecitas-Cuatricentenario line. During 2011 and 2012, there were some transfers of energy made from Colombia to Venezuela, due to shortages in Venezuela, over this line under an agreement between the presidents of both nations. The agreement covers estimated transactions of 30 GWh/month, with a demand of 70 MW in periods of low and medium load and of 140 MW in periods of high load. The contract was signed on February 1, 2013 for a term of eleven months and was formalized by a contract between Isagen (Colombia) and Corpoelec (Venezuela).

There is also an energy interconnection project with Venezuela, carried out by the Institute of Planning and Promotion of Energy Solutions for Non-Interconnected Zones (“IPSE”, in its Spanish acronym) pursuant to an agreement between Colombia and Venezuela. Under the terms of this agreement, Colombia will sell electricity to Venezuela at a rate that is much cheaper than the costs it incurred. Venezuela is expected to pay for the electricity in fuels rather than cash. This interconnection project is estimated to cost US$ 8 billion and contemplates the construction of a 35.6 km transmission line with a capacity of 34,500 volts in order to supply electricity to the region of San Fernando de Atabapo, Venezuela.

In the first half of 2012, CREG and the National Public Services Authority of Panama (“ASEP”, in its Spanish acronym) issued resolutions that provided for enhancing the process for tendering of rights to construct the future interconnection line between Colombia and Panama.

The resolutions also complement pre-existing resolutions by providing for provisions that allow Panamanian distribution companies to participate in future tenders in Colombia. The most important resolutions issued by Colombia are (i) CREG-002-2012, which attempts to resolve the discrepancies between firm capacity in Panama and the OEF in Colombia; (ii) CREG-004-2012, which outlines the exchanges in conditions of rationing; and (iii) CREG 057-2012, which is an operative agreement between the operators of the systems of Colombia and Panama. Panama has also issued parallel resolutions that enable Colombian companies to participate in tenders in Panama as International Interconnection Agents.

Emgesa, Isagen, Celsia and its subsidiary EPSA participated in the tender process to obtain line capacity rights in Panama that took place in August 21, 2012. These companies were able to participate in the tender by forming subsidiaries in Panama and complying with all requirements under Panamanian law, including the provisions relating to guarantees.

In June 2012, Interconexión Eléctrica Colombia-Panamá (“ICP”), which is jointly owned by Interconexión Eléctrica de Colombia (“ISA”) and the state-owned Empresa de Transmisión Eléctrica de Panamá (“ETESA”), was entrusted with the construction of an interconnection project and was allowed to join the tender for capacity rights. ICP submitted the base amount that is necessary to participate in the tender and proceeded to obtain prequalifications in July and August. However, the tender process was suspended indefinitely on August 19, 2012. This was primarily due to financial reasons as the Panamanian Government, citing budget constraints, refused to provide a firm commitment to contribute capital.

ICP is expected to continue to seek financial support in order to ensure the viability of the project and reduce uncertainties for the participants. With the support from the Interamerican Development Bank (“IDB”), ICP has hired a consultant to carry out a study that will explore alternatives plans that would result in more competitive energy prices and greater business opportunities. The Colombian government is also in conversations with its Panamanian counterpart in order to restart the process.

In November 2012, the Declaration of Santiago was signed by Chile, Colombia, Ecuador, Peru and Bolivia. The main purpose of this declaration was to facilitate regional electricity transaction by harmonizing regulatory frameworks of the member countries.

Gas Market

Natural gas is important for the Colombian electricity sector as natural gas is a key fuel for generation. The Colombian natural gas market operates under monopolistic conditions and basically consists of a primary market, secondary market and one short-term market. Supply contracts and transportation contracts are traded under bilateral negotiation schemes or through auctions.

As a result CREG is considering a proposal to promote competition between agents. The proposal seeks to reform the wholesale market for natural gas and ensure that it operates under the principles of transparency and liquidity. The proposal also outlines entities that are eligible to participate in each market, the types of permitted transactions and the kind of contracts that may be entered into. It even seeks to create standardized force majeure provisions for such contracts in order to clarify the responsibilities of the parties. The proposal is expected to be take effect during 2013.

Regulation of Distribution Companies

Distributors (or network operators) are responsible for planning, investing, operating and maintaining electricity networks below 220 kV (regional transmission systems (“STR”, in its Spanish acronym) and local distribution systems (“SDL” , in its Spanish acronym)). Any customer may access the distribution network by paying a connection fee. Under this scheme, the distributor is a passive agent who does not buy energy and is only responsible for transporting it and controlling the technical energy losses.

Distribution Tariff-Setting Process

CREG regulates distribution prices that allow distribution companies to recover costs, including operating, maintenance and capital costs under efficient operations. Distribution charges are set by CREG for each company based on the replacement cost of the existing distribution assets, the cost of capital, as well as operational and maintenance costs that depend on the voltage level.

The methodology for remunerating the distribution business segment was defined by CREG in 2008. The WACC was set at 13.9% before taxes for assets operating above 57.5 kV and 13.0% before taxes for assets operating under this threshold. CREG also defined a methodology for the calculation of distribution charges by creating an incentive scheme for administrative, operating and maintenance costs, service quality and energy losses. During 2009, after auditing the information reported by the companies, CREG established the distribution charges applicable until October 2013. Accordingly, it is expected that CREG will issue a new distribution charge methodology during 2013 and new distribution charges will be approved during 2014.

The distribution charges are defined for four different voltage levels which are applied depending on the customer’s connection point as follows:

Level 1: less than 1 kV;

Level 2: at least 1 kV but less than 30 kV;

Level 3: at least 30 kV but less than 57.5 kV; and

Level 4: at least 57.5 kV but less than 220 kV.

Charges are set for a five-year period and are updated monthly according to the PPI.

Incentives and Penalties

In December 2011, CREG defined a coverage mechanism, so traders, who serve as final customers, have to guarantee distributors the payment of the STR and SDL tariffs. CREG established that this kind of traders must use one of the following instruments, in order to provide security of payment to distributors: bank guarantees, stand-by letters of credit letters (either domestic or international) and monthly prepayments.

At the same time, CREG defined new regulation related to non technical losses. It defined that the companies that face higher losses than those approved in current regulation should design a plan to reduce them. The cost of the plan will be approved by CREG and is going to be paid by customers. Also, it established that companies that face lower losses than those currently approved must send to the Commission a new loss trend that will be included in the tariff. Finally, CREG established that non technical losses must be assumed by both distributors and traders, who serve as final customers, according to their demand.

The distribution business has tariff incentives contingent on the quality of service. Distributors also have to make compensatory payments to customers when it cannot meet the established continuity criteria. In 2012, CREG established the new quality of service regulation for the STR. Specifically, it defined incentives for Non-Provided Energy and provided that companies must compensate customers for any the service interruptions in the STR.

Also in 2012, CREG defined the power quality regulation. Overall, it established minimum quality standards and designed a mechanism in which customers can present their claims to distribution companies and receive compensation if standards are not accomplished by the company. This mechanism introduces new measurement requirements.

Regulation in Transmission

Transmission companies which operate at no less than 220 kV constitute the National Transmission System, or NTS. They are required to provide access to third parties on equal conditions and are authorized to collect a tariff for their services. The transmission tariff includes a connection charge that covers the cost of operating the facilities, and a usage charge, which applies only to traders.

CREG guarantees an annual fixed income to transmission companies. Income is determined by the new replacement value of the network and equipment and by the resulting value of bidding processes awarding new projects for the expansion of the NTS. This value is allocated among the traders of the NTS in proportion to their energy demand.

The expansion of the NTS is conducted according to model expansion plans designed by the Mining and Energy Planning Agency (“UPME”, in its Spanish acronym) and pursuant to bidding processes opened to existing and new transmission companies, which are handled by the Colombian MME in accordance with the guidelines set by CREG. The construction, operation and maintenance of new projects is awarded to the company that offers the lowest present value of future cash flows needed for carrying out the project.

In 2012, CREG established the new quality of service regulation for the NTS. It defined incentives for Non-Provided Energy, so companies compensate customers by diminishing their charges, according to the service interruptions in the NTS.

In 2012, the UPME also developed processes to select investors for an interconnection project that will connect some of futures generating plants. Processes performed were: UPME 02-2010 Termocol, UPME 01-2010 Alferez, UPME 05-2009 Quimbo and UPME 02-2009 Armenia. EEB was awarded in 2012 the UPME-05-2009 tender within this scheme for the design, procurement, construction, operation and maintenance of the Quimbo 230 kV substation. This new electricity interconnection project is part of the expansion of the NTS and will strengthen the electricity service in the southwest of the country.

Trading Regulation

The retail market is divided into regulated and unregulated customers. Customers in the unregulated market may freely and directly enter into electricity supply contracts with a generator or a distributor, acting as traders, or from a pure trader. The unregulated customer, which for 2012 represented about 34% of the market, consists of customers with a peak demand in excess of 0.1 MW or a minimum monthly energy consumption of 55 MWh.

Trading involves reselling the electricity purchased in the wholesale market. It may be conducted by generators, distributors or independent agents, which comply with certain requirements. Parties freely agree upon trading prices for unregulated customers.

Trading on behalf of regulated customers is subject to the “regulated freedom regime” under which tariffs are set by each trader using a combination of general cost formulas given by CREG and individual trading costs approved by CREG for each trader. Since CREG approves limits on costs, traders in the regulated market may set lower tariffs for economic reasons. Tariffs include, among other things, energy procurement costs, transmission charges, distribution charges and a trading margin.

The trading tariff formula became effective on February 1, 2008. The main changes to this formula were the establishment of a fixed monthly charge and the introduction of reduction costs of non-technical energy losses in the trading charges. In addition, CREG allows traders in the regulated market to choose tariff options to manage tariff increments.

In order to improve wholesale price formation, CREG is designing a new energy procurement scheme based on long term energy bids, known as Organized Market (“MOR”, in its Spanish acronym). The final rules for this new system are not available, but CREG has this issue on its 2013 agenda.

In May 2009, a company called Derivex was created so as to incorporate an energy derivatives market. In October 2010, Derivex began its operation with the first electricity forward derivative contract.

In December 2011, CREG issued the Retailing Code, which includes specific rules that improve retailers’ relations with other electricity market members. It establishes new regulations about energy measurement, non technical losses, the retailers’ connection to the wholesale electricity market, and the retailers’ credit risks, among other considerations.

Tariffs to Final Customers

The energy trader is responsible for charging the electricity costs to end customers and to transfer their payments to the industry’s agents. The tariffs applied to regulated customers are calculated pursuant to a formula established by CREG. This formula reflects the costs of the industry: generation, transmission, distribution (depending on the customer’s connection level), trading losses, constraints, administrative costs, and market operating costs.

In addition, the final costs of the service are affected by subsidies and / or contributions that are applied according to the socio-economic level of each customer. When subsidies exceed contributions, the Colombian government covers the difference. The subsidies mechanism is suffering some modifications. Colombian MME’s Resolution 18 1479 that was published in August 2012 modifies the subsidy removal method for residential customers whose consumption exceeds the subsistence consumption, as established in article 2 of Resolution 18 1272 of 2011. Colombian MME’s Decree 011 2012 regulating the Social Energy Fund (“FOES”, in its Spanish acronym) as provided in article 103 of Law 1450 of 2011 was also published in 2012. The purpose of FOES is to cover up to CPs 46 per kWh of the value of electricity for subsistence consumption of residential customers belonging to income groups 1 and 2 of the least developed rural areas.

Another factor that affects the final tariff is the Distribution Area which established a single tariff for the distribution companies in adjacent geographic zones.

Environmental Regulation

The environmental framework in Colombia was established by Law 99/1993, which also established the Colombian Ministry of the Environment as the authority for determining environmental policies. The Colombian Ministry of Environment defines issues, executes policies and regulations that focus on the recovery, conservation, protection, organization, administration and use of renewable resources.

Any entity planning to develop projects or activities relating to generation, interconnection, transmission or distribution of electricity that may result in environmental deterioration must first obtain environmental permits and licenses and also establish environmental management plans.

According to Law 99, generation plants that have a total installed nominal capacity above 10 MW are required to contribute to the conservation of the environment. Hydroelectric power plants must pay 6% of their generation and thermoelectric plants must pay 4% of their generation in addition to a tariff that is annually determined. This payment is made monthly to the municipalities and environmental corporations where these facilities are located.

Law 1450 of 2011 issued the National Development Plan 2010-2014. The plan establishes that between 2010 and 2014, the government must develop strategies for environmental sustainability and risk prevention of environment risks. These include measures such as the national plan for adaptation to climate change, the environmental licensing process and environmental impact studies.

In 2011, Institutional Decree 3,570 established a new regulatory structure for the environment, creating the Colombian Ministry of Environment and Sustainable Development (previously, the functions of the Ministry of the Environment were established in conjunction with functions of the Ministry of Housing). The main objective of the Colombian Ministry of Environment and Sustainable Development is the formulation and management of environmental and renewable natural resource policies. In 2012, the Colombian Ministry of Environment and Sustainable Development published several resolutions. Resolution 1517 of 2012 established the procedures relating to the Environmental Compensation for Biodiversity Loss while Decree 1640 of 2012 set forth regulations for the planning and management of hydrographic basins. In addition, Resolution 1526 of 2012 established the procedural requirements for the subtraction of the forest areas protected by Law 2 of 1959.

In 2012, the Colombian Ministry of the Environment and Sustainable Development included the NAMA (Nationally Appropriate Mitigation Action) in the CDM (Clean Development Mechanism) & NAMA Portfolio.

NAMA and CDM are two mechanism established by the United Nations in order to promote the developments of project which reduce emissions of greenhouse gases in certain countries (listed in Exhibit I of the Kyoto Protocol), for example, electric vehicles promoted by Endesa.

The Colombian Ministry of the Environment and Sustainable Development publishes on an annual basis the progress reports for the portfolio projects of CDM and NAMA under development in Colombia. This gives interested parties a chance to buy CERs (Certified Emission Reduction) in connection with CDM projects and also provides financing opportunities in the case of NAMA projects.

In December 2012 the UPME published the Resolution 0563, which establishes the procedure for the exclusion of sales tax for the programs or activities related to reduced energy consumption and energy efficiency.

In the last few years, the environmental regulation for the electricity sector has been focused on regulating power plant emissions, hydro policies (including water discharges and basin organizations), and environmental licensing and penalties.

Peru

Industry Overview

Industry Structure

In the Wholesale Electricity Market (“Peruvian MEM”, in its Spanish acronym) there are four categories of local agents: generators, transmitters, distributors and large customers.

The following chart shows the relationships among the various actors in the SEIN:

LOGO

The generation segment is composed of companies which own generation plants. This segment is noted for being a competitive market in which prices tend to reflect the marginal cost of production.

Electricity generators, as energy producers, have capacity and energy sale commitments with their contracted customers. Generators may sell this capacity and energy to both distributors and unregulated customers.

The energy received by a generator’s unregulated and regulated customers does not necessarily coincide with the energy produced by that supplier since the generation plants’ production is allocated by the Committee of Economic Operation of the System (“COES”, in its Spanish acronym), the system operator, through a centralized dispatch. The transfer cost is minimized through a consideration of the variable production costs of each power plant, regardless of their contractual commitments. Therefore, there is a short-term market also managed by the COES, where an economic balance is made between the energy produced and the consumption required by the generators’ customers.

The generation plants’ production and the customers’ energy consumption at the nodal short-term marginal cost are valued, and the deficit generators pay for the energy purchased from surplus generators. The balance made in connection with energy sales is also carried out with respect to capacity, in which case the price of the capacity corresponds to a price regulated by the Supervising Entity on Investment in Energy and Mining (“Osinergmin”, in its Spanish acronym), the Peruvian regulatory electricity authority.

The settlements made by the COES also include payments and/or collections for complementary services such as frequency and tension regulation. They also consider compensation for operating cost overruns, such as the operation at minimum load, random operational tests, etc.

Regulation DS 027-2011-EM of June 2011 establishes that as of January 2014, several actors may also participate as buyers in the short-term market, in addition to the generators. These other actors include distributors (in order to meet the demand of their unregulated customers), large customers with demand over 10 MW, and a group of unregulated customers whose aggregate demand exceeds 10 MW.

The transmission system is made up of transmission lines, substations and equipment for the transmission of electricity from the production points (generators) to the consumption centers or distribution points. Transmission in Peru is defined as all lines or substations with a tension higher than 60 kV. Some generation and distribution companies also operate sub-transmission systems at the transmission level.

Electricity distribution is an activity carried out in the concession areas granted to different distribution companies.

Customers with a capacity demand lower than 200 kW are considered regulated customers, and their energy supply is considered to be a public service. Customers whose capacity demand is within the range of 200-2,500 kW are free to choose whether to be considered regulated or unregulated customers. Once this type of customer chooses to be a regulated or unregulated customer, the customer has the obligation to remain in that category for at least three years. If the customer wants to change its category from regulated to unregulated customer, or vice versa, it shall provide at least one year advance notice.

There is only one interconnected system, the SEIN, and several isolated regional and smaller systems that provide electricity to specific areas. According to the National Institute of Statistics of Peru (“INEI”, in its Spanish acronym), as of the third quarter of 2012, 92% of the population obtained electricity through the public network, including 98.5% in urban and 72.7% in rural areas.

Principal Regulatory Authorities

The Peruvian Ministry of Energy and Mining (“MINEM”) defines energy policies applicable nationwide, regulates environmental matters applicable to the energy sector and oversees the granting, supervision, maturity and termination of licenses, authorizations and concessions for generation, transmission, and distribution activities. On August 10, 2012, Regulation DS 030-2012-EM was published, which amends the articles of organization and defines the functions of MINEM and the Natural Gas Management Department .

The Agency for the Promotion of Private Investment (“PROINVERSIÓN”) is a public entity responsible for attracting private investment in public utilities and infrastructure works. It also advises regarding the difficulties faced by investors in making their investments.

The Osinergmin is an autonomous public regulatory entity that controls and enforces compliance with legal and technical regulations related to electrical and hydrocarbon activities, controls and enforces compliance with the obligations stated in the concession contracts, and is responsible for the preservation of the environment in connection with the development of these activities. Osinergmin’s Tariff Regulatory Bureau has the authority to publish the regulated tariffs. It also controls and supervises the bidding processes required by distribution companies to purchase energy from generators.

The COES coordinates the SEIN’s short, medium- and long-term operations at minimum cost, maintaining the security of the system and optimizing energy resources. It also plans for the SEIN’s transmission development and manages the short-term market.

The National Institute for Defense of Competition and Intellectual Property (“INDECOPI”, in its Spanish acronym) is responsible for promoting competition, protecting customer rights and safeguarding all forms of intellectual property.

The General Electricity Authority (“DGE”, in its Spanish acronym) is the regulatory technical entity responsible for evaluating the electricity sector, and proposes the necessary regulations for the development of the electricity generation, transmission and distribution activities.

The Peruvian Ministry of Environment (“MINAM”, in its Spanish acronym) defines environmental policies applicable nationwide and is the head of the national environmental management system, which includes the National Environmental Impact Assessment System, the National Environmental Information System, the Protected Natural Areas System, as well as the management of natural resources in its area of competence, biodiversity and climate change, among others.

The Electricity Law

General

The general legal framework applicable to the Peruvian electricity industry includes: the Law of Electricity Concessions (Decree Law 25,844/1992) and its ancillary regulations, the Law to Secure the Efficient Development of Electricity Generation (Law 28,832/2006), the Technical Regulation on the Quality of the Electricity Supply (Supreme Decree 020/1997), the Electricity Import and Export Regulation (Supreme Decree 049/2005), the Antitrust Law for the Electricity Sector (Law 26,876/1997), and the law that regulates the activity of Osinergmin (Law 26,734/1996, together with Law 27,699/2002).

Some of the characteristics of the regulatory framework are (i) the separation of the three main activities: generation, transmission and distribution; (ii) freely-determined prices for the supply of energy in competitive market conditions; (iii) a system of regulated prices based on the principle of efficiency together with a bidding regime; and (iv) private operation of the interconnected electricity systems subject to the principles of efficiency and quality of service.

Law 29,852/2012 and Regulation 021-2012-EM created the Hydrocarbons Energy Security System and the Fund of Social Energy Inclusion (“FISE”, in its Spanish acronym). These laws also created a system of social compensation and universal service for the most vulnerable sectors of the population which will be financed by surcharges on the electricity billing of unregulated customers (equivalent to the surcharge that exists today for regulated customers on the Electrical Social Compensation Fund (“FOSE”, in its Spanish acronym)), transport surcharges for hydrocarbon-derivate liquids and natural gas multi-pipelines and surcharges on the use of the natural-gas pipeline.

Osinergmin and distribution companies will be the administrators of the FISE, which funds will be directed to (i) the massification of natural gas to vulnerable sectors, (ii) develop new energy sources like photovoltaic cells, solar panels, etc., and (iii) supply liquefied petroleum gas (“LPG”) to vulnerable sectors.

Law 29,969/2012 provides for the massification of natural gas. State electricity distributors are authorized to carry out natural-gas programs, including the distribution of natural gas in their concession area. They will also be able to associate with companies specializing in the development of gas-distribution projects. Within a maximum term of 3 years from the start of the gas distribution, MINEM will start the process of promoting private investment for the granting of the gas-distribution concession of gas by the pipeline network.

Law 29,970/2012 guarantees energy security and promotes the development of the petro-chemical complex in the south of the country. Under this law, the following agendas have been declared as a matter of national interest: (i) guaranteeing energy security, (ii) transporting ethane to the south of Peru; and (iii) constructing regional pipelines in the regions of Huancavelica, Junín and Ayacucho and linking them with the existing gas pipelines.

Limits and Restrictions

Since the enactment of the Law of Electricity Concessions, vertical integration is restricted, and thus activities in the generation, transmission and distribution segments must be developed by different companies. The Antitrust Law for the Electricity Sector regulates the cases in which vertical and horizontal integration is admissible.

An authorization is compulsory for those electricity companies that hold more than 5% of another business segment, either before or as a result of a merger or integration. An authorization is also required for the horizontal integration of generation, transmission and distribution activities which result in a market share of 15% or higher of any business segment, either before or as a result of any operation.

Such authorizations are granted by the Institute for Defense of the Consumer and Intellectual Property, using the market share information provided by Osinergmin.

Regulation of Generation Companies

Concessions

Generation companies that own or operate a power plant with an installed capacity greater than 500 kW require a concession granted by the MINEM. A concession for electricity generation activity is an agreement between the generator and MINEM, while an authorization is merely a unilateral permit granted by said public entity. Authorizations are granted by the MINEM for an unlimited period of time, although their termination is subject to the same considerations and requirements as the termination of concessions under the procedures set forth in the Law of Electricity Concessions, and its related regulations.

In order to receive a concession, the applicant must first request for a temporary concession of two years, and must subsequently apply for a definitive concession.

In order to receive an authorization, the applicant must file a petition before the MINEM. If the petition is admitted and no opposition is presented, the MINEM grants the authorization to develop generation activities for unlimited time, subject to compliance with applicable regulations.

Dispatch and Pricing

The coordination of electricity dispatch operations, the setting of spot prices and the control and management of economic transactions that take place in the SEIN are controlled by COES. Generators can sell energy directly to large customers and buy the deficit or transfer the surplus between contracted energy and actual production in the pool at the spot price. Resolution 080-2012-OS/CD was published during 2012, establishing the criteria and methodology for deciding the real-time operation under exceptional conditions as declared by the MINEM.

Sales by Generation Companies to Unregulated Customers

Sales to unregulated customers are carried out at mutually agreed prices and conditions, which include tolls and compensation for the use of transmission systems and, if necessary, to distribution companies for the use of their network.

Sales to Distribution Companies and Certain Regulated Customers

Sales to distributors can be under bilateral contracts at a price no greater than the regulated price in the case of regulated customers, or at an agreed price in the case of unregulated customers. In addition to the bilateral method allowed under the Law of Electricity Concessions, Law 28,832 has also established the possibility that distributors may meet their unregulated or regulated customers’ demand under contracts signed following a capacity and energy supply tender process.

Sales of Capacity of Other Generation Companies

Contracts between generators and distributors and/or unregulated customers relate generally to purchases and sales of capacity and the energy associated with consumption of capacity.

The purchase/sale of capacity between generators occurs in the short-term market as a consequence of an economic balance between the valuation of the remunerated firm capacity of a generator made at the regulated capacity price (the guaranteed capacity revenue), and the valuation of distribution customers’ capacity needs, valued at the regulated capacity price and/or unregulated customers’ needs valued at the mutually agreed price (the capacity purchase expenses.)

As the contracting of capacity of a generator and its valuation do not necessarily coincide with the guaranteed capacity revenue, there can be trading of capacity between generators.

The guaranteed capacity revenue of each generator is the sum of the guaranteed revenues of its generation units. The remunerated firm capacity of each generation unit results from considering all the units that, ordered by their variable costs and considering the effect of the transmission network, is taken into account for a theoretical dispatch to meet the demand of the system during the monthly peak demand at the lowest optimal cost.

Generators may engage in the direct sale of firm capacity through free negotiations.

Regulatory Charges

In addition to taxes applicable to all industries (mainly an income tax and a value added tax), the electricity industry operators are subject to a special regulation contribution that compensates the costs incurred by the state in connection with the regulation, supervision and monitoring of the electricity industry. The applicable rate for this contribution is up to 1% of the annual billing of each company and the funds levied are distributed proportionally to MINEM and Osinergmin.

Generators that also have hydroelectric plants pay a water royalty as a function of the hydroelectric energy produced and the regulated energy tariff at peak hours.

Incentives and Penalties

During 2009, MINEM carried out several studies which concluded that there will be lack of power generation capacity in the system, in the near future. MINEM recommended the construction of new power plants that would serve as backup (Cold Reserve Project) in order to guarantee the flow of electricity to the system and avoid blackouts. As a result, PROINVERSIÓN carried out a public bid in August 2010, seeking to secure investments for three projects located in Talara, Trujillo and Ilo that will add another 800 MW to the system. The bid resulted in only two of the projects being awarded: Talara (200 MW, for Empresa Eléctrica de Piura, S.A. (“EEPSA”), a subsidiary of Endesa Latinoamérica) and Ilo (400 MW, for Enersur, an unrelated company). These plants will receive regular payments for being permanently available to operate and provide energy to the SEIN whenever the COES calls on them and will also be reimbursed for the fuel costs incurred for generating electricity. The Trujillo generation facility was later substituted by the Eten generation facility, and awarded to Planta de Reserva Fría de Generación de Eten S.A. (200 MW).

An international tender was held in 2012 for the concession for the Cold Reserve Project for the Pucallpa (Ucayali) and Puerto Maldonado (Madre de Dios) plants, which were awarded to Consorcio Energía Perú S.A. The term for the construction of the plants will be 30 months from the signing of the contracts and the concession covers a period of 20 years plus the construction period. The Pucallpa thermal plant will require an investment of around US$ 31.5 million and will have a capacity between 35 and 40 MW, covering 80% of the energy demand. The Puerto Maldonado thermal plant will require an investment of around US$ 18.5 million, will have a capacity between 15 and 18 MW, covering 100% of the energy demand.

PROINVERSIÓN established February 28, 2013 as the date to submit offers for the international public tender that is intended to promote private investments for the Hydroelectric Plants project (CH Molloco—310 MW), which is located in the hills of the department of Arequipa.

Services provided by generation, transmission and distribution companies have to comply with technical standards stated in the Technical Regulations on the Quality of the Electric Supply. Failure to do so might result in the imposition of fines by Osinergmin.

In 2008, due to gas transport and electricity transmission problems, Osinergmin defined a new rule to calculate spot prices through December 2013. Decree 049/2008 established two models, one which represented a theoretical dispatch without considering any restrictions and another that considered real dispatch with restrictions. The spot price is obtained from the theoretical dispatch, and the additional operating costs resulting from system restrictions are paid to the affected generators through a mechanism established by the authority.

Generators receive a capacity payment whose main component is the product of an annual calculation that considers firm power of every power plant connected to the system. Every year, Osinergmin sets the power price that shall be assigned and paid to each generator pursuant to this concept.

Electricity Exports and Imports

A 220 kV transmission line has been implemented for the interconnection with Ecuador, with a limited capacity of 160 MW. However, the line has not operated continuously because of regulatory issues. During June and August 2011, Peru imported energy from Ecuador due to the lack of generation in northern Peru and transmission problems to that zone in the SEIN. In 2012, Peru imported 4.5 GWh of electricity from Ecuador due to the maintenance of the Talara Zorritos line (3.9 GWh in February 2012) and the TGN4 Malacas power plant (0.6 GWh in March 2012.) All of the exports to Ecuador totaling 5.5 GWh occurred in August and September 2012 (1.9 GWh and 3.6 GWh, respectively.)

Internal regulations were also approved for the application of Decision 757 of the Andean Community of Nations (“CAN”, in its Spanish acronym), which establishes that when bilateral electricity transactions are carried out with other countries of the CAN, the Economic Operation Committee of the SEIN should send to the MINEM and to Osinergmin weekly reports showing that priority has been given to supplying the domestic market (Supreme Decree 011-2012-EM).

In addition to the interconnection with Ecuador, the governments of Peru and Brazil in 2010 signed the “Agreement between the Republic of Peru and the Federal Republic of Brazil for the supply of electricity to Peru and export of surpluses to Brazil”, whose main purpose is the exploitation of Peruvian hydroelectric resources in the Amazon basin. In January 2012, Peru created a commission for handling the aspects contemplated in that agreement. The general framework establishes that the accumulated capacity of the generation plants that can be committed to export to Brazil is a maximum of 7,200 MW and dispatch will have the following order of priority: ( i) the Peruvian regulated market, ( ii) the Peruvian unregulated market, and lastly, ( iii) the Brazilian market. As of the date of this Report, the process is on hold, and is expected to be approved by the Peruvian Congress that currently is under the study of the Commission of Andean, Amazonian and Afro-Peruvian Peoples, Environment and Ecology.

The governments of Peru and Chile have established a bilateral working group to discuss energy matters. The purpose of the working group is to identify and take advantage of the potential synergies between the two countries. The first few meetings of this group took place in 2011. At the request of the presidents of both nations, the working group is expected to propose a framework for an agreement in connection with both countries’ electricity integration that would establish the general rules for energy exchanges between them. As of the date of this Report, both countries have conducted negotiations but a final agreement is still pending.

Regulation of Distribution Companies

Bids for Supplying Regulated Customers

The Law to Secure the Efficient Development of Electricity Generation established a bidding regime for the acquisition of energy and capacity by distributors through a mechanism to determine prices during the life of a contract. The approval of this mechanism is important to generators, because it sets a mechanism for determining a price for the duration of a contract that is not fixed by the regulator.

The new contracts to sell energy to distribution companies for resale to regulated customers must be made at fixed prices determined by public bids. Only a small part of the electricity purchased by distribution companies (included in old contracts) is still maintained at node prices. These are set annually by Osinergmin and are the maximum prices for electricity purchased by distribution companies that can be transferred to regulated customers in those contracts.

Distribution Tariffs to Final Customers

The electricity tariff for regulated customers includes charges for capacity and energy for generation and transmission and for the VAD which considers a regulated return on investments, operating and maintenance fixed charges and a standard percent for energy distribution losses.

Distribution Tariff-Setting Process

The VAD is set every four years. Osinergmin classifies companies into groups, according to “typical distribution areas,” based on economic factors that group companies with similar distribution costs due to population density, which determines equipment requirements in the network.

Actual return on investment for a distribution company depends on its performance relative to the standards chosen by the Osinergmin for a theoretical model company. The tariff system allows for a greater return to distribution companies that are more efficient than the model company. Tariff studies are performed by the Osinergmin and distribution companies. Preliminary tariffs are calculated as a weighted average of the results of the Osinergmin commissioned study and the companies’ study, with the results of the Osinergmin’s study bearing twice the weight of the companies’ study. Preliminary tariffs are then tested to ensure that they provide an average actual annual internal rate of return between 8% and 16% on the replacement cost of electricity-related distribution assets.

The last process for setting distribution tariffs was held in November 2009 and will be in effect until November 2013.

Regulatory Charges

The regulatory charges applied to the energy sales in distribution activities are:

•

The contribution to regulatory authorities (Osinergmin, MINEM), which represents 1% of total sales.

•

The Electrical Social Compensation Fund (“FOSE”, in its Spanish acronym), created to promote permanent access to the public electricity service for low-income residential customers. This Fund established a cross subsidy system among customers that benefits customers with monthly consumption below 100 kWh through fixed and proportional discounts.

•

The rural electrification charge is a contribution for promoting the efficient and sustainable electrification development in rural, isolated or frontier areas of the country. The contribution of the electricity customers is of 0.002 UIT (a tax unit) per MWh billed, with the exception of those which are not served by the SEIN.

Incentives and Penalties

Law 28,832 and DS 052-2007-EM (“General Regulations of the Supply Auctions”) affecting energy purchases state that if auctions are called for with an anticipation of over three years, distributors will receive a payment incentive which will be added to the generator price of the auctions, and then passed through to customers. This incentive cannot be higher than 3% of the tariffs applied.

The distribution concessionaire may lose its concession if it does not provide evidence of a guaranteed supply for the following 24 months, at a minimum, unless it has called for public auctions according to the current norm and has not received offers sufficient to comply with its total requirements for the established period.

Regulation in Transmission

Transmission activities are divided in two categories: “principal,” which are for common use and allow the flow of energy through the national grid; and “secondary,” which are those lines that connect a power plant with the national grid that connects principal transmission with the distribution network or that connect directly to certain final customers. Law 28,832 also defined “guaranteed transmission systems” and “complementary transmission systems,” applicable to projects commissioned after the enactment of that law. Guaranteed system lines are the result of a public bid and complementary system lines are freely constructed and exploited as private projects. Principal and guaranteed system lines are accessible to all generators and allow electricity to be delivered to all customers. Transmission concessionaires receive an annual fixed income, as well as variable tariff revenues and connection tolls per kW. The secondary and complementary system lines are accessible to all generators but are used to serve only certain customers who are responsible for making payments related to their use of the system.

Environmental Regulation

The environmental legal framework applicable to energy related activities in Peru is set forth in the Environmental Law (Law 28,611/2005) and in the Regulation for Environmental Protection regarding Electricity Activities (Supreme Decree 029-94-EM). The MINEM dictates the specific environmental legal dispositions applicable to electricity activities, and Osinergmin is in charge of supervising certain aspects of their application and implementation. According to the Environmental Law, the Peruvian Ministry of Environment has the principal duties of (i) designing the general environmental policies to every productive activity; and (ii) establishing the main guidelines of the different government authorities for their specific environmental sector regulations. During 2010, most supervision functions regarding the application and implementation of the Environmental Law’s dispositions were transferred from Osinergmin to the Peruvian Ministry of the Environment.

Renewable Energy Resources (“RER”) for electricity generation are considered to be from biomass, wind, solar, geothermal and tidal sources, plus hydroelectric plants whose installed capacity does not exceed 20 MW.

In 2008, the authority issued regulations to promote the use of RER. The principal investment incentives established by these regulations are (i) an objective percentage of national electricity consumption, set every five years, to be covered by RER-based electricity generation, not including hydroelectric plants (for the first five-year period, this percentage is 5%); (ii) through tenders of energy to be covered by RER, the winning investor is guaranteed a firm price for the energy injected into the system during the supply contract period of up to 20 years; and (iii) priority in the dispatch of load and access to transmission and distribution networks.

The second RER tender was made in August 2011 for the 1,300 GWh/year, which must be generated from non-hydroelectric sources. Out of 21 initiatives proposed, 473 GWh were awarded to three projects.

In addition, other regulations establish tax incentives, including (i) accelerated depreciation of assets for income tax purposes, and (ii) the advanced recovery of the sales tax. In 2011, the permanent congressional commission approved Law 29,764 extending these tax benefits through 2020.

Law 29,968/2012 created the National Environmental Certification Service for Sustainable Investments (“SENACE”, in its Spanish acronym), a specialized public organization with technical autonomy and a separate legal constitution, reporting to the Peruvian Ministry of the Environment. This organization is responsible for reviewing and approving detailed environmental impact studies of public, private or mixed capital investment projects, whether national or multi-regional, that involve activities, construction and other commercial and service activities whose characteristics, importance and/or location can result in significant environmental impacts, with the exception of those expressly excluded by Supreme Decree with the consenting vote of the Council of Ministers.

SENACE seeks to implement just one system of environmental administrative procedures to guarantee sustainable investments through the implementation of a sole window of environmental certification (Ventanilla Única de Certificación Ambiental).

Raw Materials

For information regarding Enersis’ raw materials, please see “Item 11. Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”

C.	Organizational Structure.

Principal Subsidiaries and Affiliates

We are part of a group led by the Italian company, Enel. Enel owns 92.1% of Endesa Spain, and the latter owns 60.6% of the share capital of Enersis through its Spanish subsidiary Endesa Latinoamérica.

Enel is a publicly held company headquartered in Italy, primarily engaged in the energy sector, with a presence in 40 countries worldwide and more than 97,000 MW of net installed capacity. It provides service to more than 61 million customers through its electricity and gas businesses.

The following chart shows the relative position of Enersis in the Enel Group, as well as our most important operating subsidiaries and jointly-controlled companies:

LOGO

The companies listed in the following table were consolidated by us as of December 31, 2012. In the case of subsidiaries, our economic interest is calculated by multiplying our percentage economic interest in a directly held subsidiary by the percentage economic interest of any entity in the chain of ownership of such ultimate subsidiary.


Principal Subsidiaries and Country of Operations	% Economic Ownership of Main Subsidiary by Enersis			Consolidated Assets of Each Main Subsidiary		Operating Income of Each Main Subsidiary
	(in billions of Ch$ except percentages)
Electricity Generation
Endesa Chile (Chile) (1)		60.0	%		6,488.7		632.2
Endesa Fortaleza (Brazil)		54.3	%		199.4		41.9
Cachoeira Dourada (Brazil)		54.1	%		200.8		105.1
Electricity Transmission
CIEN (Brazil)		54.3	%		361.0		36.9
Electricity Distribution
Chilectra (Chile)		99.1	%		1,303.5		133.3
Ampla (Brazil)		70.2	%		1,234.6		173.7
Edesur (Argentina)		65.4	%		324.6		(54.1	)
Edelnor (Peru)		57.5	%		525.6		70.1
Coelce (Brazil)		35.3	%		874.8		131.0
Codensa (Colombia)		21.7	%		1,237.3		245.2
Other non-electricity businesses
IMV (Chile)		100.0	%		68.7		13.1

(1)	Endesa Chile consolidates all generation facilities in Chile, Argentina, Colombia and Peru.

Generation and Transmission Segment

Endesa Chile (Chile)

Endesa Chile is a publicly held electricity generation company in Chile. On a stand-alone basis, excluding direct subsidiaries in Chile (described below), Endesa Chile has a total installed capacity of 3,757 MW as of December 31, 2012, with 17 generation facilities. Of the total installed capacity, 61% is from hydroelectric power plants, including Ralco with 690 MW, El Toro with 450 MW, Rapel with 377 MW, and Antuco with 320 MW, among others. Regarding our thermoelectric facilities, nearly 67% are gas/fuel oil power plants, and the rest are coal-steam power plants. Our economic interest in Endesa Chile is 60.0%.

Celta (Chile)

Celta was incorporated in 1995 to build and operate two thermoelectric plants in the SING: a coal-fired plant with an installed capacity of 158 MW and a gas/fuel oil power plant with 24 MW of installed capacity. Celta is a wholly-owned subsidiary of Endesa Chile. Our economic interest in Celta is 60.0%.

Endesa Eco (Chile)

In April, 2005, Endesa Chile created Endesa Eco S.A., whose objectives are the promotion and development of renewable energy projects such as mini-hydro, wind, geo-thermal, solar and biomass power plants and to act as the depositary and trader of emission reduction certificates obtained by these projects. As of December 31, 2012, Endesa Eco’s installed capacity was 87 MW. Endesa Eco is a wholly-owned subsidiary of Endesa Chile. Our economic interest in Endesa Eco is 60.0%.

San Isidro (Chile)

San Isidro was incorporated in Chile in 1996, as a wholly-owned subsidiary of Endesa Chile, to build and operate a 379 MW combined-cycle thermal plant in Quillota, in the Valparaíso Region. The plant began commercial operations in 1998. A 220 kV transmission line of 9 kilometers was built to connect this thermal plant to the SIC. This transmission system is owned by Transmisora Eléctrica de Quillota Ltda. (Transquillota), in which San Isidro has a 50% interest. On May 1, 2012, Pangue, a former subsidiary of Endesa Chile, was merged into San Isidro. Pangue contributed with a 467 MW installed capacity hydroelectric power station on the Bío-Bío River, whose first unit started operations in 1996 while the second unit started operations in 1997. As of December 31, 2012, Endesa Chile holds 95.6% of San Isidro’s share capital, reflecting also the merger between Pangue and San Isidro, as part of the organizational simplification announced by Endesa Chile on February 29, 2012. Our economic interest in San Isidro is 57.4%.

Pehuenche (Chile)

Pehuenche, a generation company connected to the SIC, owns three hydroelectric facilities south of Santiago in the high rainfall hydrological basin of the Maule River, with a total installed capacity of 699 MW. The 570 MW Pehuenche plant started operations in 1991, the 89 MW Curillinque plant started operations in 1993, and the 40 MW Loma Alta plant started operating in 1997. Endesa Chile holds 92.7% of Pehuenche. Our economic interest in Pehuenche is 55.6%.

Endesa Costanera (Argentina)

Endesa Costanera is a publicly held electricity generation company in Argentina, with 2,324 MW of total installed capacity in Buenos Aires, including six steam turbines with an aggregate capacity of 1,138 MW which burn oil and gas, and two natural gas combined-cycle facilities with a total capacity of 1,186 MW. Endesa Costanera company was acquired from the Argentine government after the privatization of Servicios Eléctricos del Gran Buenos Aires S.A. Endesa Chile owns 69.8% of Endesa Costanera. Our economic interest in Endesa Costanera is 41.9%.

El Chocón (Argentina)

El Chocón is an electricity generation company, incorporated in Argentina, located between the Neuquén and Río Negro provinces, in the Comahue Basin in southern Argentina. It has two hydroelectric power stations with an aggregate installed capacity of 1,328 MW. A 30-year concession, which expires in 2023, was granted by the Argentine government to our subsidiary, Hidroinvest S.A., which bought 59.0% of the shares in July 1993 during the privatization process. Endesa Chile operates El Chocón for a fee pursuant to an operating agreement with a term equal to the duration of the concession. Endesa Chile beneficially owns 65.4% of El Chocón. Our economic interest in El Chocón is 39.2%.

Edegel (Peru)

Edegel, an electricity generation company, was acquired by Endesa Chile in 1995. It currently owns seven hydroelectric plants and two thermal plants, with a combined installed capacity of 1,657 MW. In October 2009, Endesa Chile purchased an additional 29.4% stake in Edegel from Generalima, a subsidiary of Endesa Latinoamérica. Consequently, Endesa Chile increased its beneficial ownership in Edegel from 33.1% to 62.5%. Our economic interest in Edegel is 37.5%.

Edegel holds an 80% share of Chinango S.A.C., and Peruana de Energía S.A.A. owns the remaining 20% share.

Emgesa (Colombia)

Emgesa has a total installed generating capacity of 2,914 MW of which 85% corresponds to hydroelectric power plants and the remaining to thermoelectric power plants. In September 1997, Central Hidroeléctrica Betania, through its former subsidiary Inversiones Betania S.A. and in association with Endesa Desarrollo, S.A. of Spain, was awarded control of Emgesa through Capital de Energía S.A. (CESA), with 48.5% of the shares. In January 2006, due to a company restructuring, CESA ceased to exist. In March 2006, Emgesa purchased the assets of Termocartagena (208 MW) through a public tender process. Empresa de Energía de Bogotá S.A. has a direct 51.5% equity interest in Emgesa. Endesa Chile’s beneficial ownership in Emgesa is 26.9%; however, it has 31.3% of the voting rights, and due to a transfer of rights from another subsidiary of Endesa Spain, Endesa Chile has the right to appoint the majority of the Board members and, therefore, controls Emgesa. Our economic interest in Emgesa is 16.1%.

Endesa Brasil (Brazil)

In 2005, Endesa Brasil was formed as a company to manage all generation, transmission and distribution assets that Endesa Latinoamérica, a subsidiary of Endesa Spain, held together with Enersis, Endesa Chile and Chilectra in Brazil; namely, through Ampla, Endesa Fortaleza, CIEN, Cachoeira Dourada and Coelce. Enersis has a beneficial interest of 54.3% in Endesa Brasil.

Endesa Fortaleza (Brazil)

Located in the municipality of Caucaia, 50 kilometers from the capital of the State of Ceará, Endesa Fortaleza is a combined-cycle power plant of 322 MW fueled by natural gas, with a capacity to generate a third of the electricity requirements of Ceará, with a population of 8.2 million people. As of December 31, 2012, Endesa Fortaleza has a concession that expires in 19 years. Endesa Fortaleza is wholly-owned by Endesa Brasil. We hold a 54.3% economic interest in Endesa Fortaleza.

Cachoeira Dourada (Brazil)

Located in the State of Goias, 240 kilometers south of Goiania, Cachoeira Dourada is a hydro run-of-the-river plant using the flows from the Paranaiba River, with ten generating units totaling 665 MW of installed capacity. Cachoeira Dourada started operations in 1997, and as of December 31, 2012 it has a concession that expires in 15 years. Endesa Brasil has a 99.6% ownership interest in Cachoeira Dourada and our economic interest is 54.1%.

CIEN (Brazil)

CIEN, a Brazilian transmission company wholly-owned by Endesa Brasil, transmits electricity through two transmission lines between Argentina and Brazil covering a distance of 500 kilometers, with a total interconnection capacity of 2,100 MW. As of December 31, 2012, CIEN-Line 1 has a concession that expires in 8 years and CIEN-Line 2 has a concession that expires in 10 years. CIEN consolidates CTM and TESA, which operate the Argentine side of the interconnection line with Brazil. Our economic interest in CIEN is 54.3%.

Distribution Segment

Ampla (Brazil)

Ampla is the second largest electricity distribution company in the State of Rio de Janeiro, Brazil as measured by the number of clients and annual energy sales. Ampla is engaged mainly in the distribution of electricity to 66 municipalities of the State of Rio de Janeiro and serves 2.7 million customers in a concession area of 32,615 square kilometers. As of December 31, 2012, Ampla has a concession that expires in 14 years. We have a 70.2% economic interest in Ampla.

Coelce (Brazil)

Coelce is the sole electricity distributor in the State of Ceará, in northeastern Brazil. As of December 31, 2011, Coelce served over 3.3 million customers within a concession area of 148,825 square kilometers. As of December 31, 2012, Coelce has a concession that expires in 15 years. We hold a 35.3% economic interest in Coelce.

Chilectra (Chile)

Chilectra is one of the largest electricity distribution companies in Chile as measured by the number of regulated clients, distribution assets and energy sales. Chilectra operates in a concession area of 2,118 square kilometers in the Santiago metropolitan area serving approximately 1.7 million customers. Our economic interest in Chilectra is 99.1%.

Edesur (Argentina)

Edesur is the second largest electricity distribution company in Argentina measured by energy purchases. Edesur operates in a concession area of 3,309 square kilometers in the south-central part of the greater Buenos Aires metropolitan area serving approximately 2.4 million customers under a concession that expires in 75 years. Our economic interest in Edesur is 65.4%.

Codensa (Colombia)

Codensa, an electricity distribution company that serves a concession area of 18,217 square kilometers in Bogotá and 96 other municipalities in the Departments of Cundinamarca, Tolima and Boyacá, serves approximately 2.7 million customers. We hold a 21.7% economic interest in Codensa, and due to a transfer of rights from another Endesa Spain subsidiary, we appoint the majority of the Board members and, therefore, control Codensa.

Edelnor (Peru)

Edelnor, a Peruvian electricity distribution company, operates in a concession area of 1,517 square kilometers. It has an exclusive concession to distribute electricity in the northern part of the Lima metropolitan area, some provinces of the Lima department such as Huaral, Huaura, Barranca and Oyón, and in the adjacent province of Callao. As of December 31, 2012, Edelnor distributed electricity to approximately 1.2 million customers. We hold a 57.5% economic interest in Edelnor.

Inmobiliaria Manso de Velasco (Chile)

Inmobiliaria Manso de Velasco, a wholly-owned subsidiary, develops real estate projects in Chile and represents less than 0.3% of our 2012 operating revenues before consolidation adjustments.

Selected Related and Jointly-Controlled Companies

HidroAysén (Chile)

HidroAysén was incorporated in March 2007. Endesa Chile has a 51% ownership interest and Colbún S.A. the remaining 49%. The company was created to develop and exploit a hydroelectric project located in the Aysén Region, in the southern region of Chile. Our economic interest in HydroAysén is 30.6%.

GasAtacama (Chile)

Endesa Chile has a 50% beneficial interest in GasAtacama, located in the northern region of Chile. GasAtacama has a four-unit combined cycle power plant of 780 MW and a gas pipeline that allows for the import of gas from Argentina. Since 2007, Southern Cross Latin America Private Equity Fund III, L.P. owns the remaining 50% beneficial interest. Our economic interest in GasAtacama is 30.0%.

Transquillota (Chile)

Transquillota was incorporated in June 1997, as part of an agreement between San Isidro and Colbún, for the joint development of a 220 kV transmission line for dispatching the energy produced and connecting San Isidro and Nehuenco (a subsidiary of Colbún) plants to the Central Interconnected Electric System (SIC). The 220 kV transmission line is 8 kilometers long. The property is equally divided among San Isidro and Nehuenco. Our economic interest in Transquillota is 28.7%.

For additional information of all Endesa Chile’s subsidiaries and jointly-controlled companies, please refer to Appendix 1 of our Consolidated Financial Statements.

D.	Property, Plants and Equipment.

Our Property, Plants and Equipment are concentrated primarily on electricity generation, distribution and transmission assets in the five countries in which we operate.

Property, Plants and Equipment of Generating Companies

We conduct our generation and transmission businesses through our subsidiaries, Endesa Chile and Endesa Brasil. In Chile, Endesa Chile owns 24 generation power plants and consolidates revenues from four others, for a total of 28 plants. Endesa Chile also consolidates revenues from other non wholly-owned generation companies in Argentina, Colombia and Peru, which involve an additional 26 generation power plants. Through Endesa Brasil, through whom we conduct our Brazilian operations, we consolidate revenues from two other generation power plants, thereby aggregating a total of 56 power plants in South America. Through Endesa Brasil, we also own and operate a transmission system consisting of two 2,100 MW transmission lines 500 kilometers long, linking Rincón de Santa María in Argentina with Itá in the State of Santa Catarina in Brazil.

A substantial portion of our generating subsidiaries’ cash flow and net income is derived from the sale of electricity produced by its electricity generation facilities. Significant damage to one or more of their main electricity generation facilities or interruption in the production of electricity, whether as a result of an earthquake, flood, volcanic activity or any other such cause, could have a material adverse effect on their operations. Our generating subsidiaries insure all electricity generation facilities against damage due to earthquakes, fires, floods, other Acts of God (but not for prolonged droughts, which is a risk not covered by insurance companies) and from damage due to third-party actions, based on the appraised value of the facilities as determined from time to time by an

independent appraiser. Based on geological, hydrological and engineering studies, management believes that the risk of an event with a material adverse effect is remote. Claims under our generating subsidiaries’ insurance policies are subject to customary deductibles and other conditions. We also maintain business interruption insurance providing for coverage for failure of any of our facilities for a period of up to 24 months, including the deductible period.

The insurance coverage taken for non-Chilean property is approved by each company’s management, taking into account the quality of the insurance companies and the needs, conditions and risk evaluations of each generating facility, and is based on general corporate guidelines.

All insurance policies are purchased from reputable international insurers. We continuously monitor and meet with the insurance companies in order to obtain what we believe is the most commercially reasonable insurance coverage.

The following table identifies the power plants that we own, at the end of each year, and their basic characteristics:

Installed Capacity

Country/Company

Power Plant Name

Power Plant Type (1)

2012

2011

2010

Argentina

Endesa Costanera

Total

2,324

Endesa Costanera Steam Turbine

Steam Turbine/Natural Gas+ Fuel Oil

1,138

Endesa Costanera Combined Cycle II

Combined Cycle/Natural Gas+Diesel Oil

859

Central Buenos Aires Combined Cycle I

Combined Cycle/Natural Gas

327

El Chocón

Total

1,328

Chocón

Reservoir

1,200

Arroyito

Pass-through

128

Total Capacity in
Argentina

3,652

Brazil

Cachoeira Dourada

Pass-through

665

Endesa Fortaleza

Combined Cycle/Gas

322

Total Capacity in Brazil

987

(1)	Reservoir and pass-through refer to a hydroelectric plant that uses the force of a dam or a river, respectively, to move the turbines which generate electricity.

“Steam” refers to the technology of a thermal power plant that uses natural gas, coal, diesel or fuel oil, to produce steam that moves the turbines to generate electricity.

“Gas Turbine” (GT) or “Open Cycle” refers to the technology of a thermal power plant that uses either diesel or natural gas to produce gas that moves the turbines to generate electricity.

“Combined Cycle” refers to the technology of a thermal power plant that uses natural gas, diesel oil or fuel oil to generate gas that first moves the turbines to generate electricity and then recovers the gas that escapes from that process to generate steam to move another turbine.

“Wind Farm” refers to the technology that transforms the kinetic energy of wind into electricity.

Continued


			Installed Capacity
Country/Company	Power Plant Name	Power Plant Type	2012		2011		2010
					MW

Chile
Endesa Chile	Total			3,757		3,407		3,407
	Total Hydroelectric			2,290		2,290		2,290
	Rapel	Reservoir		377		377		377
	Cipreses	Reservoir		106		106		106
	El Toro	Reservoir		450		450		450
	Los Molles	Pass-through		18		18		18
	Sauzal	Pass-through		77		77		77
	Sauzalito	Pass-through		12		12		12
	Isla	Pass-through		70		70		70
	Antuco	Pass-through		320		320		320
	Abanico	Pass-through		136		136		136
	Ralco	Reservoir		690		690		690
	Palmucho	Pass-through		34		34		34
	Total Thermal			1,467		1,117		1,117
	Bocamina (1)	Steam Turbine/Coal		478		128		128
	Diego de Almagro	Gas Turbine/ Diesel Oil		24		24		24
	Huasco	Gas Turbine/IFO 180 Oil		64		64		64
	Taltal	Gas Turbine/Natural Gas+Diesel Oil		245		245		245
	San Isidro 2	Combined Cycle /Natural Gas+Diesel Oil		399		399		399
	Quintero	Gas Turbine/Natural Gas+Diesel Oil		257		257		257
Pehuenche	Total			699		699		699
	Pehuenche	Reservoir		570		570		570
	Curillinque	Pass-through		89		89		89
	Loma Alta	Pass-through		40		40		40
Pangue	Pangue (2)	Reservoir		0		467		467
San Isidro	Total			846		379		379
	San Isidro	Combined Cycle /Natural Gas+Diesel Oil		379		379		379
	Pangue (2)	Reservoir		467		0		0
Celta	Total			182		182		182
	Tarapacá	Steam Turbine/Coal		158		158		158
	Tarapacá	Gas Turbine/Diesel Oil		24		24		24
Endesa Eco	Total			87		87		87
	Canela	Wind Farm		18		18		18
	Canela II	Wind Farm		60		60		60
	Ojos de Agua	Pass-through		9		9		9
GasAtacama	Atacama	Combined Cycle /Natural Gas+Diesel Oil		390		390		390

Total Capacity in Chile				5,961		5,611		5,611

(1)	On October 28, 2012, Bocamina II (350 MW) started commercial operation.

(2)	Empresa Eléctrica Pangue S.A. was merged with San Isidro on May 2, 2012. San Isidro is the surviving company. Pangue’s installed capacity is included in San Isidro from that date.

Continued


			Installed Capacity
Country/Company	Power Plant Name	Power Plant Type	2012		2011		2010
					MW

Colombia
Emgesa	Total			2,914		2,914		2,914
	Guavio	Reservoir		1,213		1,213		1,213
	Paraíso	Reservoir		276		276		276
	La Guaca	Pass-through		325		325		325
	Termozipa	Steam Turbine/Coal		236		236		236
	Cartagena	Steam Turbine/ Natural Gas		208		208		208
	Minor plants (1)	Pass-through		116		116		116
	Betania	Reservoir		541		541		541

Total Capacity in Colombia				2,914		2,914		2,914

Peru
Edegel	Total			1,463		1,474		1,474
	Huinco	Pass-through		247		247		247
	Matucana	Pass-through		129		129		129
	Callahuanca	Pass-through		80		80		80
	Moyopampa	Pass-through		66		66		66
	Huampani	Pass-through		30		30		30
	Santa Rosa (2)	Gas Turbine/Diesel Oil		426		429		429
	Ventanilla (2)	Combined Cycle/Natural Gas		485		493		493
Chinango	Total			194		194		194
	Yanango	Pass-through		43		43		43
	Chimay	Pass-through		151		151		151

Total Capacity in Peru				1,657		1,668		1,668

Consolidated Capacity				15,171		14,832		14,832

(1)	Minor plants collectively have a total capacity of 116 MW. As of December 31, 2012 Emgesa owned and operated six minor plants: Charquito, El Limonar, La Tinta, Tequendama, La Junca and San Antonio.

(2)	The installed capacity of this generation power plant in 2012 is the result of tests made by the Peruvian Economic Operating Committee of the Interconnected System.

As of December 31, 2012, the Company had received the international standard ISO 14,001 certification for 97.7% of its installed capacity in South America, which included 55 out of 56 generation facilities that produced 99.1% of the total annual generation according to the ISO 14,001 standard.

Investment Projects Completed during 2012

Chile. Bocamina Power Plant Expansion, Second Unit

Located in the district of Coronel, Bío-Bío Region, the project benefits from the existing harbor services, as well as some ancillary facilities of the first unit built for coal storing and ashes disposal. This second unit will use pulverized coal and technology for emissions reduction.

On October 28, 2012, the unit was synchronized to the SIC, reaching an installed capacity of 350 MW, and was declared to be in commercial operation.

This project was financed with internally generated funds.

Projects under Construction

Colombia. El Quimbo Hydroelectric Project

El Quimbo hydroelectric project is located in the department of Huila, on the Magdalena River, upstream of the Betania power plant. Its installed capacity will be 400 MW through two generation units. This project is being financed mainly with external sources, through local and international bond issuances, and to a lesser extent, with Emgesa’s internally generated funds. In 2008, as a result of the awarding process, Emgesa assumed a Firm Energy Obligation for El Quimbo starting in December 2014 and increasing annually from 1.1 GWh/day during the first year up to 4.5 GWh/day from December 2017 to November 2034. In 2009, the Colombian Ministry of the Environment approved the environmental license and building permission.

The principal contracts, corresponding to the civil works and the manufacture, supply and assembly of the equipment, were awarded to the Impregilo-OHL consortium and the Alstom — Schrader Camargo consortium.

The main advances in civil works in 2012 were:

in February, the completion of the construction of the diversion tunnel;

in September, the completion of the construction of the bridge over the river Páez; and

in November, the final diversion of the river Magdalena.

The first supplies (turbine parts for the first unit) were received at the site on December 3, 2012 pursuant to the equipment contract.

Colombia. Salaco Hydroelectric Project

The Salaco project consists of the recovery of 145 MW in the old generation chain of river Bogotá through major maintenance and modernization of six units currently out of service. The units to be recovered are located at three plants: Salto II, Laguneta and Colegio, which operate in a limited manner as minor plants. The increase in capacity will permit greater generation of approximately 482 GWh/year.

In 2012, the equipment diagnoses, technical specifications and tendering of all the processes were carried out. In December 2012, the project was approved by the board of Emgesa and the contracting began for the maintenance and modernization of the six generation units.

Projects under Development

The estimated investments disclosed in this section aggregate the funds that we expect to spend in U.S. dollars each year. Budgeted amounts include connecting lines that could eventually be owned by third parties and paid as tolls. In general terms, projects are expected to be financed with resources to be provided by external financing as well as internally generated funds for each of the companies described.

We continuously analyze different growth opportunities in the countries in which we participate. Thus, the expected start-up for each project is continuously assessed and will be defined based on the commercial opportunities and our financing capacity to fund these projects. The most relevant projects in the pipeline are as follows:

Chile. Los Cóndores Project

The Los Cóndores project will be located in the Maule Region. It consists of the construction of a pass-through hydroelectric plant of 150 MW installed capacity, which will use the waters from the Maule Lake reservoir through an adduction system 12 kilometers long. The power plant will be connected to the SIC at the Ancoa substation through a 220 kV transmission line.

The feasibility study for the project has been completed. It considers the use of TBM technology (tunnel machinery), which is more efficient, has higher safety standards and a lower environmental impact, for the construction of the tunnel connecting the project with the Maule Lake. The environmental permit for this generation power plant was obtained in 2011. The basic engineering was completed at the end of 2011.

100

The transmission line project obtained its environmental qualification resolution in May 2012.

Chile. Neltume Hydroelectric Project

The Neltume project is located in Los Ríos Region, on the upper part of the Valdivia River basin. The Neltume project consists of a 490 MW installed capacity pass-through hydro plant. The power plant will be connected to the SIC through a 220 kV transmission line from Neltume to Loncoche, via Pullinque.

The Neltume power generation project has been under the environmental permission process since December 2010. During 2011, the basic engineering studies began and complementary studies for environmental process were developed. During 2012 the basic engineering studies were completed. In 2013, we expect to obtain the environmental authority permissions for the power plant.

Chile. HidroAysén Project

The HidroAysén hydroelectric project consists of five hydroelectric power stations, with an aggregate installed capacity of 2,750 MW, two of which are in the Baker River (660 MW and 360 MW) and the other three are in the Pascua River (770 MW, 500 MW and 460 MW). Connection to the SIC consists of a 500 kV high-voltage direct current (HVDC) transmission line whose length depends on whether the injection of energy is made in the central zone of the SIC (1,912 km further north) or at the SIC’s southernmost point (1,000 km further north).

On May 9, 2011, the environmental authority approved the Environmental Impact Assessment presented for the HidroAysén project. However, HidroAysén presented an appeal against the environmental qualification resolution issued, requesting the revision of certain demands. This has to be analyzed and resolved, together with those presented by other parties, by a committee of public cabinet members.

In April 2012, the Supreme Court in Santiago ruled in favor of HidroAysén and rejected the appeals presented by environmental organizations, thereby bringing to an end a long judicial process brought by opponents of the project.

In May 2012, our partner Colbún S.A., the holder of 49% of HidroAysén, recommended to the company’s board to suspend the process of obtaining environmental approval for the transmission line until there is a consensus on the country’s energy policy.

In August 2012, HidroAysén restructured its management team and created the position of Community and Communications Manager, based in the region of Aysén, in order to strengthen the company’s links with the community and promote a policy of transparency, dialogue and direct communication with the residents. Since then, HidroAysén has focused its efforts on the region in order to comply with its commitments to the community, address concerns about the project, correct erroneous information introduced by opponents and mainly progress in the development of a socially-viable project.

Important decisions are expected for 2013, including the resolution of the Committee of Ministers that will review the arguments regarding the environmental qualification resolution made by HidroAysén and the opponents of the project.

Chile. Punta Alcalde Power Plant

The project consists of the construction of a thermoelectric plant with two steam-coal units, with a total installed capacity of 740 MW, located in the Atacama Region. The plant will be connected to the SIC at the Maitencillo substation through a 220 kV transmission line.

In 2009, Endesa Chile presented its environmental impact study to the authority for assessment. During 2011, there was a regulatory change regarding emissions requirements which resulted in significant changes to the project. On June 25, 2012, the Atacama Region environmental evaluation commission (CEA) decided to reject the project. Endesa Chile then appealed to the Committee of Ministers. On December 3, 2012, this committee voted unanimously to reverse the decision of the CEA and gave its environmental approval for the project. It is expected that the Committee of Ministers will issue the environmental qualification resolution for the project in early 2013.

101

During 2012, progress was made in the preparation of the feasibility studies and the EIA for the transmission line to connect the plant to the SIC in order to submit it to the environmental evaluation process.

Chile. Renaico Wind Farm

This project is located in the 9th Region, in the town of Renaico. It consists of 44 wind-generators of 2 MW each, with a bushing height of 95 m, which will generate a total of 255 GWh/year. The energy produced will be taken by two transmission lines: (i) the main one in a simple-circuit line of 27 km in 220 kV to the new Bureo substation to be built in the 8th Region, and (ii) the second in 66 kV, which will be connected with the Renaico-Angol line.

During 2012, the basic engineering was finished and tenders were issued for the supply contracts. The environmental qualification resolution for the wind farm and the transmission line in 220 kV were also obtained.

Peru. Curibamba Hydroelectric Project

This relates to a pass-through power plant with an effective capacity of 188 MW to produce 1,010 GWh/year. This would be located upstream from the intake of the Chimay hydroelectric power plant in the department of Junín and would use the waters of the Comas and Uchubamba Rivers through an 8.1 km pressure tunnel.

The plant’s basic engineering designs were concluded in 2012 and presented to the system operator (COES) for the pre-operative study, and the tendering process for the civil works contracts and plant equipment began. The basic designs of the transmission line are finalized for more than 80% of its length.

In October 2012, the plant’s environmental impact study (EIA) was approved. The EIA of the transmission line is pending resolution.

Brazil. Tapajós Hydroelectric Complex

The Tapajós complex (10.7 GW) is located in the state of Pará and consists of five hydroelectric plants: São Luiz do Tapajós (6,133 MW), Jatobá (2,338 MW), Cachoeira do Caí (802 MW), Jamanxim (881 MW) and Cachoeira dos Patos (528 MW).

In order to conduct feasibility and environmental studies for the development of the complex, Endesa Brasil joined with eight other companies (the public companies Eletrobras, Eletronorte, Cemig and Copel, and the private companies EDF, Neoenergia, GDF/Suez and Camargo Corrêa). Each company will finance the necessary investments in equal parts.

The focus in 2012 was on the São Luiz do Tapajós project, which resulted in significant progress in the engineering feasibility and environmental studies.

Brazil. Tabajara Hydroelectric Project

This project is a hydroelectric plant located in Río Ji-Paraná, state of Rondônia, with 350 MW installed capacity.

In 2012, Endesa Brasil joined with Eletronorte, Furnas and Queiroz Galvão in order to conduct environmental and feasibility studies. These studies are in their final stages.

Brazil. Hydroelectric Plant on the River Aripuanã

The River Aripuanã projects are located in the state of Amazonas. Endesa Brasil has chosen to study the Prainha (796 MW) and Sumaúma (458 MW) hydroelectric projects.

In 2012, Endesa Brasil obtained the approval from ANEEL for the studies and asked the Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis for authorization for the environmental studies. Endesa Brasil also took part in these projects in the public tender by Eletronorte and was chosen to participate in these studies.

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Brazil. Carnaúba Combined Cycle

The Carnaúba project relates to a natural gas combined-cycle thermal plant with 350 MW of capacity, located alongside the Fortaleza plant. The project has acquired environmental and water-availability licenses.

Property, Plants and Equipment of Transmission and Distribution Companies

We also have significant interests or investments in electricity distribution. The description for each distribution company is included in this “Item 4. Information on the Company.” The table set forth below describes our main equipment used for our distribution business, such as transmission lines, substations, distribution networks and transformers.

We are insured against damage to substations, transformers that are within the substations, the distribution network that is not farther than one kilometer from the substations and administrative buildings. Risks covered include losses caused by fires, explosions, earthquakes, floods, lightning, damage to machinery and other such events. Insurance policies include liability clauses, which protect our companies from complaints made by third parties.

Transmission lines and the equipment attached to them do not qualify as insurable assets for property damage, although they have insurance policies including civil liability clauses for damages against third parties caused by these transmission installations. This criterion applies in the case of the Argentina-Brazil interconnection line, our main transmission asset, for which there is insurance coverage for damage to the assets and civil liability for the Garabí conversion station, the Argentina/Brazil connection substations and up to one km of lines from the substations. Only third-party liability coverage is applicable for the rest of the transmission lines.

TABLE OF DISTRIBUTION FACILITIES

General Characteristics


		Concession Area (km²)		Transmission Lines (km) (1)
	Location	Concession Area (km²)		2012		2011		2010
Chilectra	Chile		2,118		355		355		355
Edesur	Argentina		3,309		1,146		1,139		1,162
Edelnor (2)	Peru		1,517		471		464		449
Ampla	Brazil		32,615		2,363		2,339		2,339
Coelce	Brazil		148,825		4,628		4,504		4,351
Codensa	Colombia		14,087		1,247		1,246		1,240
EEC (3)	Colombia		5,186		35		35		35

Total			207,657		10,245		10,082		9,932

(1)	The transmission lines consist of circuits with voltages in the 27-220 kV range.

(2)	The concession area figure differs from previous disclosures as it was reviewed in 2012 and updated accordingly.

(3)	We include 49% of EEC.

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Power and Interconnection Substations and Transformers (1)


	2012						2011						2010
	Number of Substations		Number of Transformers		Capacity (MVA)		Number of Substations		Number of Transformers		Capacity (MVA)		Number of Substations		Number of Transformers		Capacity (MVA)
Chilectra		54		157		7,448		53		155		7,023		53		152		6,904
Edesur		68		174		11,607		66		171		11,547		67		173		11,481
Edelnor		32		73		3,050		30		69		2,883		29		67		2,757
Ampla		117		223		4,542		116		221		4,452		116		222		4,386
Coelce		102		161		2,467		99		160		2,406		98		156		2,273
Codensa		63		229		8,795		63		225		8,619		62		211		7,665
EEC (2)		23		34		177		23		33		174		23		31		170

Total		459		1,051		38,086		450		1,034		37,104		448		1,012		35,636

(1)	Voltage of these transformers is in the range of 500 kV (high voltage) and 7 kV (medium voltage).

(2)	We include 49% of EEC.

Distribution Network - Medium and Low Voltage Lines (1)


	2012				2011				2010
	Medium Voltage (km)		Low Voltage (km)		Medium Voltage (km)		Low Voltage (km)		Medium Voltage (km)		Low Voltage (km)
Chilectra		5,070		10,655		4,993		10,476		4,945		10,285
Edesur		7,373		16,007		7,347		15,985		7,318		15,937
Edelnor		4,064		20,731		3,854		19,826		3,694		19,234
Ampla		33,642		17,600		33,078		17,459		32,562		17,278
Coelce		81,460		47,968		79,759		46,115		78,578		45,684
Codensa		19,563		27,285		19,276		23,586		19,104		22,579
EEC (2)		3,706		5,528		3,724		5,474		3,624		5,608

Total		154,879		145,774		152,031		138,921		149,824		136,605

(1)	Medium voltage lines: 7 kV—34.5 kV; low voltage lines: 380-110 V.

(2)	We include 49% of EEC.

Transformers for Distribution (1)


	2012				2011				2010
	Number of Transformers		Capacity (MVA)		Number of Transformers		Capacity (MVA)		Number of Transformers		Capacity (MVA)
Chilectra		28,570		7,011		28,384		6,782		28,362		6,500
Edesur		23,195		5,781		23,520		5,651		23,583		5,508
Edelnor		10,122		1,519		9,878		1,443		9,665		1,347
Ampla		113,256		4,338		110,473		4,115		107,663		3,882
Coelce		137,729		4,593		134,132		4,508		128,836		4,411
Codensa		66,720		8,306		66,570		8,301		65,836		8,055
EEC (2)		6,918		323		6,808		312		6,687		304

Total		386,510		31,871		379,765		31,112		370,632		30,007

(1)	Voltage of these transformers is in the range of 34.5 kV (medium voltage) and 110 V (low voltage).

(2)	We include 49% of EEC.

Major Encumbrances

Endesa Costanera’s supplier debt with Mitsubishi Corporation corresponds to the remaining payments for the purchase of equipment. As of December 31, 2012, the value of the assets pledged to secure this debt was Ch$ 39 billion. Additionally, Endesa Costanera has granted liens for Ch$ 18 billion as of December 31, 2012 in favor of Credit Suisse First Boston in order to guarantee a loan.

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In addition, Endesa Fortaleza executed a loan agreement with the International Finance Corporation (IFC) to finance the construction of a power plant in Brazil. Fortaleza granted liens for the IFC that include a mortgage and a pledge on assets which, as of December 31, 2012 were valued at Ch$ 118 billion. For further information, see Note 34 to our Consolidated Financial Statements.

Climate Change

In recent years, Chile and the region have seen a growing development related to non-conventional renewable energy and strategies to face climate change. This has led both the public and private sectors to conduct suitable strategies for adapting themselves to the new requirements, evidenced by legal obligations at the local level, commitments assumed by countries at the international level and the demanding requirements of the international markets in these matters.

Non-conventional renewable energies (NCRE) provide energy with minimal environmental impact and without CO₂ emissions. They are therefore considered as technological options that strengthen sustainable energy development as they supplement the production of traditional generators.

During 2012, Enersis and its subsidiaries carried out several activities and held working meetings with different public, academic and private entities, in order to learn and share experiences concerning the technical and regulatory developments in connection with NCRE and climate change at both the local and international levels, analyze and establish strategic alliances, develop social and private projects and strengthen the leadership position achieved by the Company in Chile.

The Canela wind farm (18 MW, in operation since late 2007), Ojos de Agua mini-hydroelectric plant (9 MW, in operation since 2008) and Canela II wind farm (60 MW, in operations since late 2009) are the NCRE facilities owned by Enersis, which have contributed clean and renewable energy to the national grid.

Regarding the development of CO₂ emission reduction mechanisms, during 2012, the projects in the Clean Development Mechanism (CDM) circuit were as follows:

Ojos de Agua Mini-Hydroelectric Plant: In 2009, the verification of the greenhouse gas emissions (CO2) avoided by the Ojos de Agua mini-hydroelectric plant during the previous period were begun, so as to certify and trade these emission reductions under the CDM. As a result of the verification process, during 2012, 2011 and 2010 the company has been analyzing administrative and technical modifications to the monitoring procedures in order to meet the requirements of the United Nations Framework Convention on Climate Change (UNFCCC) for CDM projects. As of the date of this Report, we are working on these administrative and technical changes and analyzing the carbon market scenarios in order to follow the next steps of the CDM project. Since its start-up in 2008, the installation has avoided the CO₂ emission of approximately 81,500 tons, which can be traded once they are verified.

Canela Wind Farm: On April 3, 2009, the UNFCCC approved the registration of the Canela project as a CDM project, which recognizes that this wind farm may verify and trade the greenhouse gas emissions it will avoid during its useful life. During 2012, we implemented a CDM procedure in order to meet the monitoring plan and the requirements of the UNFCCC. Since its start-up in 2007, the installation has avoided the CO₂ emission of approximately 82,700 tons, which will be able to be traded on carbon markets once they are verified.

Canela II Wind Farm: On August 12, 2012, the UNFCCC approved the registration of the Canela II project as a CDM project, which recognizes that this wind farm may verify and trade the greenhouse gas emissions it will avoid during its useful life. During 2012, the UNFCCC requested some clarifications and new information for the registration and finally, approved the CDM registration. Since its start-up in 2009, the Canela II wind farm has avoided the CO₂ emission of approximately 250,000 tons, which will be able to trade on carbon markets once they are verified.

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Detail of CDM projects processed in 2012 by Endesa Chile


CDM project	Company/country	Position as of December 31, 2012	Emission factor (tons CO₂e/MWh)	Approximate emissions avoided (tons CO₂e/year)
Ojos de Agua mini- hydroelectric plant	Endesa Eco (Chile)	Registered with the Executive Authority of the UNFCCC since April 2007.	0.4348	17,904 (CER still not verified) (1)
Canela wind farm	Central Eólica Canela S.A. (Chile)	Registered with the Executive Authority of the UNFCCC since April 2009. CDM procedure implemented.	0.5713	14,700 (CER still not verified)
Canela II wind farm	Central Eólica Canela S.A. (Chile)	Registered with the Executive Authority of the UNFCCC since August 2012. CDM procedure implemented.	0.6541	37,000 (CER still not verified)

(1)	CER: Certified Emission Reductions.

The greenhouse gas emissions of the Company for the last three years, including our 50% stake in GasAtacama, were 12.1 million tons in 2012, 13.3 million tons in 2011 and 11.8 million tons in 2010.

Item 4A.

Unresolved Staff Comments

None

Item 5.

Operating and Financial Review and Prospects

A.	Operating Results.

General

The following discussion should be read in conjunction with our Consolidated Financial Statements and the notes thereto, included in Item 18 in this Report, and “Selected Financial Data,” included in Item 3 herein. Our Consolidated Financial Statements as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010 have been prepared in accordance with IFRS as issued by the IASB.

1.	Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company

We are an electricity investment company that owns and operates electric power generation, transmission, and distribution companies in Chile, Brazil, Colombia, Peru and Argentina. Most of our revenues, income and cash flows come from the operations of our subsidiaries, jointly-controlled companies and associates in these five countries.

Factors such as hydrological conditions, fuel prices, regulatory developments, extraordinary actions adopted by government authorities, and economic conditions in each country in which we operate, materially affect our financial results. In addition, the results from operations and financial condition are affected by variations in exchange rates between the Chilean peso and the currencies of the other four countries in which we operate. These exchange variations may have an important impact in the consolidation of the results of our companies outside Chile. Lastly, we have certain critical accounting policies that affect our consolidated operating results.

Our commercial strategy allows the impact of significant changes in one country to be sometimes offset by opposing changes in other countries, or within generation and distribution, leading to no significant impacts on consolidated figures. The impact of these factors on us, for the years covered by this Report, is discussed below.

a.	Generation Business

A substantial part of our generation business depends on hydrological conditions prevailing in the countries where we operate, although only extreme hydrological conditions materially affect our operating results and financial condition. In terms of installed capacity in 2012, 2011 and 2010, 57%, 58% and 58% of our consolidated installed capacity, respectively, has been hydroelectric. Consolidated hydroelectric capacity was 8,666 MW, 8,675 MW and 8,675 MW as of December 31, 2012, 2011 and 2010, respectively.

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Hydrological conditions in 2012, 2011 and 2010 have adversely impacted our financial condition and results of operations. Hydroelectric generation was 34,985 GWh in 2012, 33,676 GWh in 2011, and 33,689 GWh in 2010. The higher hydroelectric generation in 2012 was associated with better conditions in Brazil, Argentina and Colombia as compared to 2011. Consolidated operating income was Ch$ 1,497 billion in 2012, Ch$ 1,566 billion in 2011 and Ch$ 1,704 billion in 2010.

Our thermal generators burn natural gas, LNG, coal or diesel. We can offset the effect of low hydrology (reservoir levels, rain and snow) in the geographical areas where we operate our plants by thermal generation and purchases. Our thermal installed capacity and the ability to purchase electricity from other generators allow us to increase thermal generation and/or purchase electricity from competitors to meet our commitments. In addition, given industry structure and the percentage of hydroelectric generation capacity in the countries where we operate, when hydrology is low, electricity prices generally increase.

Operating costs associated with thermal generation and energy purchases are higher than the variable cost of hydroelectric generation in normal hydrological conditions. The cost of thermal generation does not directly depend on hydrology but instead on global commodity prices. However, the cost of electricity purchases in the spot market does depend on hydrology and commodity prices.

The impact of low hydrology on operating results depends on the resulting movement in electricity prices in the market, the severity of the impact of hydrological conditions on our hydroelectric generation, our cost of thermal generation and the need for energy purchases. The effect of low hydrology on market prices may increase or decrease our operating margin, depending on the conditions of all relevant market factors. In recent years, low hydrology has led to a lower operating margin. For additional information on the effects of hydrological conditions on our operating results, see “Item 3. Key Information — D. Risk Factors — Since our generation business depends heavily on hydrological conditions, drought conditions may hurt our profitability.”

b.	Regulatory Developments

The regulatory frameworks governing our business in the five countries where we operate have a material effect on our results from operations. In particular, regulators set (i) generation tariffs taking into consideration factors such as fuel costs, reservoir levels, exchange rates, future investments in installed capacity and demand growth, and (ii) distribution tariffs taking into account the costs of energy purchases paid by distribution companies (which distribution companies pass on to their customers) and the “Value Added from Distribution,” or VAD, all of which are intended to reflect investment and operating costs incurred by distribution and generation companies and to allow such companies to obtain a return on their investments. The earnings of our electricity subsidiaries are determined to a large degree by government regulators, mainly through the tariff setting process.

Over the next few years, ordinary tariff reviews will continue in each country. For example, during 2013 and 2014 the tariffs of Codensa and Cundinamarca in Colombia will be reviewed. In 2014 the tariffs of Ampla in Brazil and of sub-transmission in Chile will be reviewed. In 2015, Coelce’s tariffs will be reviewed. In 2016, the distribution tariffs in Chile will be reviewed. In 2017, Edelnor’s tariffs in Peru will be reviewed. Naturally, each of these reviews presents its own particularities and challenges. In growth zones like South America, tariff revisions seek to capture economies of scale according to this growth. Provided results are achieved in this line therefore, continuity in terms of tariff recognition is maintained.

In Brazil, recent regulatory changes include the adoption of Provisional Resolution 579 of the Brazilian National Electrical Energy Agency (Agéncia Nacional de Energia Elétrica or “ANEEL”) and Law 12,783, which regulate the renewal and extension of generation, transmission and distribution concessions that expire between 2015 and 2017. Endesa Brasil is not affected directly by these regulatory changes as the terms of its concessions expire later than 2017. For additional information relating to the regulatory frameworks in the countries where we operate, see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework.”

c.	Economic Conditions

Macroeconomic conditions in the countries in which we operate have a significant effect on our operating results. For example, when a country experiences sustained economic growth, consumption of electricity by industrial and individual consumers increases. Other macroeconomic factors, such as the variation of the local currency against the U.S. dollar in the countries where we operate, may impact our results from operations, as well as assets and liabilities, depending on the percentage denominated in U.S. dollars. For example, a devaluation of local currencies against the U.S. dollar increases the cost of capital expenditure plans. For additional information, see “ Item 3. Key Information — D. Risk Factors — Foreign exchange risks may adversely affect our results and the U.S. dollar value of dividends payable to ADS holders” and “— South American economic fluctuations are likely to affect our results from operations and financial condition, as well as the value of our securities.”

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Economic Growth and Electricity Demand

Economic growth in 2012 was positive in most of the countries in which we operate, mainly based on domestic private consumptions and investment. Even though activity outside Latin America moderated more than expected due to the worldwide economic situation, leading to a weaker external demand for Latin America’s goods and services, this region showed resilience to global threats and the outlook remains better than that for the developed world. According to the IMF’s October 2012 World Economic Outlook, the estimated GDP simple average growth for Latin America and the Caribbean is 3.2% for 2012, and 3.9% for 2013. Growth will continue to be driven by many of South America’s commodity exporters (particularly Chile, Peru and Colombia) all of which are expected to grow in the range of 4% to 6% in 2012 and 2013. Growth in South America is projected to have moderated to 2.9% in 2012 and then increase to 4.0% in 2013, as the worldwide economic recovery would be consolidated and the effect of expansionary policy in some countries would begin to have an impact. Brazil’s growth in 2012 was lower than expected, which is an important cause of the weaker regional growth performance. In 2013, monetary policy easing should spur a stronger growth in Brazil, led by domestic demand.

Overall electricity demand increased in 2012, principally due to the favorable economic situation in most of the countries in which we operate. The GDP and electricity growth rate for the years 2012, 2011 and 2010 are included in the following table:


	2012		2011		2010
	GDP Growth (%)	Electricity Demand Growth (%)	GDP Growth (%)	Electricity Demand Growth (%)	GDP Growth (%)	Electricity Demand Growth (%)
Chile (1)	5.0	5.2	6.5	6.0	5.2	3.4
Argentina	2.6	4.2	8.0	5.5	7.5	5.9
Colombia	4.3	3.8	4.9	1.7	4.7	2.6
Brazil	1.5	4.5	3.8	3.4	7.5	7.1
Peru	6.0	5.9	6.2	7.5	8.3	8.5

Source:

GDP growth data was obtained from the World Economic Outlook (October 2012) of the International Monetary Fund and corresponds to real growth for 2011 and an estimate for 2012. Electricity demand growth data was obtained from sales reported by the CDEC to the CNE in the case of Chile, from electricity demand reported by CAMMESA in the case of Argentina, from total demand of the SIN reported by the XM in the case of Colombia, from energy charges reported by the ONS in the case of Brazil, and from monthly reports of tariffs and the electricity market reported by the Osinergmin in the case of Peru.

(1)	Electricity demand growth includes growth in the Chilean central interconnected electric system (Sistema Interconectado Central, or SIC) and the Chilean interconnected electric system in northern Chile (Sistema Interconectado del Norte Grande, or SING).

Local Currency Exchange Rate

Variations in the parity of the U.S. dollar and the local currency in each of the countries in which we have operations may have an impact on our operating results and overall financial position. The impact will depend on the level at which tariffs are pegged to the U.S. dollar, U.S. dollar-denominated assets and liabilities existing in the period and also the translation of financial statements of our foreign subsidiaries for consolidation purposes to the presentation currency, which is the Chilean peso.

As of December 31, 2012, we had total consolidated indebtedness of US$ 7,236 million, of which 28.6% was denominated in U.S. dollars, 29.3% in Colombian pesos, 15.7% in Brazilian reais, 18% in Chilean pesos, 6.2% in Peruvian soles, and 2.2% in Argentine pesos.

The following table sets forth the closing and average local currencies per U.S. dollar exchange rates for the periods indicated.


	Local Currency U.S. Dollar Exchange Rates
	2012				2011				2010
	Average		Year End		Average		Year End		Average		Year End
Chile (peso per U.S. dollar)		486.59		479.96		483.57		519.20		510.22		468.01
Argentina (Argentine peso per U.S. dollar)		4.55		4.92		4.13		4.30		3.92		3.98
Colombia (Colombian peso per U.S. dollar)		1,798		1,768		1,847		1,943		1,895		1,914
Brazil (reais per U.S. dollar)		1.95		2.04		1.67		1.88		1.69		1.66
Peru (sol per U.S. dollar)		2.64		2.55		2.75		2.70		2.81		2.81

Sources: Central Bank of each country.

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d.	Critical Accounting Policies

Financial Reporting Release Section 501.1 encourages all companies to include a discussion of critical accounting policies or methods used in the preparation of financial statements. Critical accounting policies are defined as those that reflect significant judgments and uncertainties which would potentially result in materially different results under different assumptions and conditions. We believe that our critical accounting policies are limited to those described below with reference to the preparation of our financial statements under IFRS. For further detail of the accounting policies and the methods used in the preparation of the financial statements, see Notes 2 and 3 to our Consolidated Financial Statements.

Impairment of Long-Lived Assets

During the period, and principally at period end, we evaluate whether there is any indication that an asset has been impaired. Should any such indication exist, we estimate the recoverable amount of that asset to determine the amount of impairment in each case. In the case of identifiable assets that do not generate cash flows independently, we estimate the recoverability of the Cash Generating Unit to which the asset belongs, which is understood to be the smallest identifiable group of assets that generates independent cash inflows.

Notwithstanding the preceding paragraph, in the case of Cash Generating Units to which goodwill or intangible assets with an indefinite useful life have been allocated, a recoverability analysis is performed routinely at each period end.

The recoverable amount is the greater between the fair value less the cost needed to sell and the value in use, which is defined as the present value of the estimated future cash flows. In order to calculate the recoverable value of property, plant, and equipment, goodwill and intangible assets, Enersis uses value in use criteria in practically all cases.

To estimate the value in use, we prepare future cash flow projections, before tax, based on the most recent budgets available. These budgets incorporate management’s best estimates of Cash Generating Units’ revenue and costs using sector projections, past experience, and future expectations.

In general, these projections cover the next ten years, estimating cash flows for subsequent years by applying reasonable growth rates, between 2.3% and 9.5%, which, in no case, are increasing nor exceed the average long-term growth rates for the particular sector and country.

These cash flows are discounted at a given pre-tax rate in order to calculate their present value. This rate reflects the cost of capital of the business and the geographical area in which the business is conducted. The discount rate is calculated taking into account the current time value of money and the risk premiums generally used by analysts for the specific business activity and the country involved.

The following discount rates, before tax and expressed in nominal terms, were applied in 2012 and 2011:


		2012		2011
Country	Currency	Minimum	Maximum	Minimum	Maximum
Chile	Chilean peso	8.0%	14.6%	8.0%	10.1%
Argentina	Argentine peso	26.0%	29.0%	23.0%	26.0%
Brazil	Brazilian reais	9.5%	18.0%	9.5%	11.6%
Peru	Nuevos soles	7.6%	12.5%	7.3%	9.3%
Colombia	Colombian peso	8.4%	14.5%	8.9%	10.9%

If the recoverable amount is less than the net carrying amount of the asset, the corresponding provision for impairment loss is recorded for the difference, and charged to “Reversal of impairment loss (impairment loss) recognized in profit or loss” in the consolidated statement of comprehensive income.

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Impairment losses recognized for an asset in prior periods are reversed when its estimated recoverable amount changes, increasing the asset’s value with a credit to earnings, limited to the asset’s carrying amount if no adjustment had occurred. In the case of goodwill, adjustments that would have been made are not reversible.

Litigation and Contingencies

We are currently involved in certain legal and tax proceedings. As discussed in Note 34.3 to our Consolidated Financial Statements, we have estimated the probable outflows of resources for resolving these claims to be Ch$ 187.7 billion. We have reached this estimate after consulting our legal and tax advisors who are carrying out our defense in these matters and an analysis of potential results, assuming a combination of litigation and settlement strategies.

Hedge Revenues Directly Linked to the U.S. Dollar

We have established a policy to hedge the portion of our revenues directly linked to the U.S. dollar by obtaining financing in this currency. Exchange differences related to this debt, as they are cash flow hedge transactions, are charged net of taxes to an equity reserve account, and recorded as income during the period in which the hedged cash flows are realized. This term has been estimated at ten years.

This policy reflects a detailed analysis of our future U.S. dollar revenue streams. Such analysis may change in the future due to new electricity regulations limiting the amount of revenues tied to the U.S. dollar.

Pension and Post-Employment Benefits Liabilities

We have various defined benefits plans for our employees. These plans pay benefits to employees at retirement and use formulas based on years of service and the compensation of the participants. We also offer certain additional benefits for some retired employees in particular.

The liabilities shown for the pensions and post-employment benefits reflect our best estimate of the future cost of meeting our obligations under these plans. The accounting applied to these defined benefit plans involves actuarial calculations which contain key assumptions that include: employee turnover, life expectancy and retirement ages, discount rates, expected returns on assets, the future level of compensation and benefits, the claims rate under medical plans and future medical costs. These assumptions change as economic and market conditions vary and any change in any of these assumptions could have an important effect on the reported results from operations.

The effect of an increase of one percentage point in the discount rate used to determine the present value of the post-employment defined benefits would decrease the liability by Ch$ 59,773 million in 2012, Ch$ 54,572 million in 2011 and Ch$ 48,203 million in 2010 and the effect of a decrease of one percentage point in the rate used to determine the present value of the post-employment defined benefits would increase the liability by Ch$ 71,632 million in 2012, Ch$ 65,050 million in 2011 and Ch$ 56,463 million in 2010.

Recent Accounting Pronouncements

Please see Note 2.2 to our Consolidated Financial Statements for additional information regarding recent accounting pronouncements.

2.	Results of Operations for the Years ended December 31, 2012 and December 31, 2011.

Net income for the year ended December 31, 2012 was Ch$ 893.6 billion, a 2.4% increase from Ch$ 872.5 billion for the year ended December 31, 2011. This result was achieved in spite of the drought that has affected the generation business in Chile for the past three years, a situation that improved to a limited extent during the second half of 2012. The increase in net income attributable to shareholders of Enersis (excluding the increase in net income attributable to non-controlling interests) was Ch$ 1.9 billion.

Operating income for the year ended December 31, 2012 was Ch$ 1,497 billion, a 4.4% decrease from Ch$ 1,566.3 billion for the year ended December 31, 2011, mainly due to the effects of the drought mentioned above.

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Revenues

Generation and Transmission Business

The following table sets forth the electricity sales of our subsidiaries and the corresponding changes for the years ended December 31, 2012 and 2011.


	Electricity sales during the year ended December 31,
	2012		2011		Change		% Change
			(GWh)
Endesa Chile (Chile) (1)		21,277		22,070		(793)		(3.6)	%
Endesa Costanera (Argentina)		8,655		8,493		161		1.9	%
El Chocón (Argentina)		3,197		2,888		309		10.7	%
Edegel (Peru)		9,587		9,450		138		1.5	%
Emgesa (Colombia)		16,304		15,112		1,193		7.9	%
Cachoeira Dourada (Brazil)		4,345		3,986		358		9.0	%
Endesa Fortaleza (Brazil)		2,947		2,842		105		3.7	%

Total		66,311		64,840		1,471		2.3	%

(1)	Includes Endesa Chile and its Chilean generation subsidiaries.

Distribution Business

Distribution revenues are mainly derived from the resale of electricity purchased from generators. Revenues associated with distribution include the recovery of the cost of electricity purchased and the resulting revenue from the VAD, which is associated with the recovery of costs and the return on the investment with respect to the distribution assets, plus the physical energy losses permitted by the applicable regulator. Other revenue derived from our distribution services consists of charges for new connections and the maintenance and rental of meters.

The following table sets forth the electricity sales of our subsidiaries, by country, and their corresponding variations for the years ended December 31, 2012 and 2011.


	Electricity sales during the year ended December 31,
	2012		2011		Change		% Change
	(GWh)
Chilectra (Chile)		14,445		13,697		748		5.5	%
Edesur (Argentina)		17,738		17,233		505		2.9	%
Edelnor (Peru)		6,863		6,572		291		4.4	%
Ampla (Brazil)		10,816		10,223		593		5.8	%
Coelce (Brazil)		9,878		8,970		908		10.1	%
Codensa (Colombia) (1)		13,364		12,857		507		3.9	%

Total		73,104		69,552		3,552		5.1	%

(1)	Values for Codensa include the proportional consolidation of 49.0% of DECSA. This consolidation also affects other figures in this section such as operating income, revenues, operating costs and number of clients.

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Revenues by Business Segment

The table below presents our revenues by business segment for 2012 and 2011.


	Year ended December 31,
	2012		2011		Change		% Change
	(in million of Ch$)
Generation and Transmission Business
Endesa and subsidiaries (Chile)		1,156,118		1,257,995		(101,877)		(8.1)	%
Endesa Costanera (Argentina)		295,140		341,824		(46,684)		(13.7)	%
El Chocón (Argentina)		49,193		48,341		852		1.8	%
Cachoeira Dourada (Brazil)		155,195		126,646		28,549		22.5	%
Endesa Fortaleza (Brazil)		139,186		129,485		9,701		7.5	%
CIEN (Brazil)		72,523		59,918		12,605		21.0	%
Emgesa (Colombia)		580,151		498,569		81,582		16.4	%
Edegel (Peru)		282,124		239,842		42,282		17.6	%
Less: Intercompany Transactions		(2,367)		(2,594)		227		(8.8)	%

Total		2,727,263		2,700,026		27,237		1.0	%

Distribution Business
Chilectra and subsidiaries (Chile)		984,738		1,046,191		(61,453)		(5.9)	%
Edesur (Argentina)		321,242		279,725		41,517		14.8	%
Edelnor (Peru)		385,013		329,309		55,704		16.9	%
Ampla (Brazil)		1,074,237		1,117,269		(43,032)		(3.9)	%
Coelce (Brazil)		806,427		859,446		(53,019)		(6.2)	%
Codensa (Colombia)		888,586		815,487		73,099		9.0	%

Total		4,460,243		4,447,427		12,816		0.3	%

Less: Consolidation Adjustments and Other Businesses		(609,839)		(612,573)		2,734		(0.4)	%

Total		6,577,667		6,534,880		42,787		0.7	%

Generation and Transmission Business: Revenues

Revenues in Chile decreased by 8.1% for the year ended December 31, 2012, mainly due to an 11.9% reduction in average energy sale prices, which in turn was a result of lower indexation of contracts to the marginal cost in Chile and to lower electricity sales, which declined 3.6% as a consequence of the expiration of GasAtacama contracts and lower hydro availability.

In Argentina, revenues of Endesa Costanera decreased 13.7% for the year ended December 31, 2012 as a result of lower average energy sale prices expressed in local currency. Electricity sales reached 8,654.7 GWh for the year ended December 31, 2012, compared to 8,493.3 GWh for the year ended December 31, 2011. Revenues of El Chocón increased 1.8%, mainly as a result of higher electricity sales in the spot market, resulting from a 16% increase in hydroelectric generation of the period. Electricity sales reached 3,196.8 GWh for the year ended December 31, 2012, compared to 2,887.7 GWh for the year ended December 31, 2011. For both Argentine companies, the net effect of translating results from the Argentine peso to Chilean peso was negative, resulting in an 8.6% decline in revenues in Chilean peso terms.

In Brazil, revenues of Cachoeira Dourada increased 22.5% for the year ended December 31, 2012, as a result of a 358.4 GWh increase in electricity sales to 4,344.5 GWh for the year ended December 31, 2012. This increase in electricity sales was primarily due to higher energy generation, in addition to the higher average sales price, expressed in local currency. Revenues of Endesa Fortaleza increased 7.5% for the year ended December 31, 2012, due to higher average sales prices, expressed in local currency, and 104.6 GWh greater electricity sales for the year ended December 31, 2012. Revenues of CIEN increased 21.0% for the year ended December 31, 2012, due to greater toll revenues that were in effect for the full year of 2012 compared to only being in effect starting in mid-April in 2011. The effect of currency translation on our revenue derived from Brazil was negative, causing a 13.9% reduction in Chilean peso terms, compared to the same period of 2011.

In Colombia, revenues of Emgesa increased Ch$ 81.6 billion, or 16.4%, for the year ended December 31, 2012, mainly as a result of a 7.9% increase in electricity sales attributable to greater hydroelectric generation. Additionally, the average energy sale price expressed in local currency increased as a result of higher wholesale market energy prices in effect since August 2012. The effect of currency translation from Colombian pesos to Chilean pesos caused a 3.4% increase in revenues in Chilean peso terms, compared to the same period of 2011.

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Revenues of Edegel, our generation company in Peru, increased Ch$ 42.3 billion, or 17.6%, for the year ended December 31, 2012. This was due to the increase in the average energy sale price, as a consequence of the higher contract prices as a result of the indexation to fuel prices and the higher node price in effect since May 2012. The effect of currency translation increased revenues by 5.0% in Chilean peso terms, compared to the same period of 2011.

Distribution Business: Revenues

In Chile, revenues of our subsidiary Chilectra declined Ch$ 61.5 billion, or 5.9%, for the year ended December 31, 2012, as a consequence of a reduction in the average energy sales price during 2012, partly offset by 748 GWh higher electricity sales, reaching 14,445 GWh for the year ended December 31, 2012 and Ch$ 4.3 billion from higher activity in other products and services businesses, relocating street lighting and networks. The number of customers increased by 21,422, exceeding 1.6 million.

In Argentina, revenues of Edesur increased by 14.8% for the year ended December 31, 2012, mainly due to higher average energy sales prices in local currency, as well as a 2.9% increase in electricity sales. Electricity sales reached 17,738 GWh for the year ended December 31, 2012. The number of customers remained constant at approximately 2.4 million. The effect of currency translation was an 8.6% reduction of revenues in Chilean peso terms, compared to the same period of 2011.

In Peru, revenues of Edelnor increased 16.9% for the year ended December 31, 2012, mainly due to an increase in electricity sales, which increased 4.4%, in addition to a higher average sales price in local currency. Other operating revenues increased by Ch$ 3.3 billion and revenues of other services increased by Ch$ 1.2 billion, mainly due to new connections. The number of customers grew by 59,027, to more than 1.2 million customers, and electricity sales reached 6,863 GWh for the year ended December 31, 2012. The effect of currency translation increased revenues by 5.0% in Chilean peso terms, compared to the same period of 2011.

In Brazil, the revenues of our subsidiary Ampla decreased 3.9% for the year ended December 31, 2012, mainly as a result of the effect of currency translation which caused a 13.9% reduction for the year ended December 31, 2012 when compared to the same period of 2011, in spite of a 5.8% increase in electricity sales and higher average energy sales prices expressed in local currency. Electricity sales for the year ended December 31, 2012 reached 10,816 GWh and the number of customers of Ampla increased by 68,849 customers, exceeding 2.7 million. Revenues of Coelce decreased 6.2% for the year ended December 31, 2012, mainly as a result of the Chilean peso translation effect, which caused a 13.9% decrease for the year ended December 31, 2012. This decrease resulted in a Ch$ 53 billion decrease in operating revenues, despite a electricity sales increase of 10.1% and increases in the average sales price in local currency. The number of customers for Coelce increased by 113,785 for the year ended December 31, 2012, to more than 3.3 million and electricity sales were 9,878 GWh for the year ended December 31, 2012.

In Colombia, revenues of our subsidiary Codensa increased 9.0% for the year ended December 31, 2012 as a result of greater electricity sales, which increased 3.9% during the period and higher average sales prices when expressed in local currency. Electricity sales reached 13,364 GWh for the year ended December 31, 2012 and the number of customers increased by 96,071 to more than 2.7 million customers. The effect of currency translation increased revenues by 3.4% in Chilean peso terms, compared to the same period of 2011.

Operating Costs

Operating costs consist primarily of electricity purchases from third parties, fuel purchases, depreciation, amortization and impairment losses, maintenance costs, tolls paid to transmission companies, and employee salaries. Operating costs also include administrative and selling expenses.

The following table shows the breakdown of our operating costs, as a percentage of total operating costs, for the years ended December 31, 2012 and 2011. Our cost structure remained substantially the same in 2012 and 2011.

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	Year ended December 31,
	2012			2011
	(percentage of total costs of operations)
Electricity purchases		36.5	%		35.5	%
Fuel purchases		15.4	%		14.9	%
Other Variable cost		12.0	%		12.9	%
Other fixed costs		10.0	%		10.9	%
Depreciation, amortization and impairment losses		9.6	%		11.3	%
Transmission tolls		9.2	%		7.9	%
Staff benefit costs		7.2	%		6.6	%

		100	%		100	%

The table below sets forth the breakdown of operating costs by company for the years ended December 31, 2012 and 2011:


	Year ended December 31,
	2012		2011		Change		% Change
	(in million of Ch$)
Generation and Transmission Business
Endesa and subsidiaries (Chile)		980,366		859,191		121,175		14.1	%
Endesa Costanera (Argentina)		317,228		335,344		(18,116)		(5.4)	%
El Chocón (Argentina)		24,328		24,599		(271)		(1.1)	%
Cachoeira Dourada (Brazil)		50,071		36,365		13,706		37.7	%
Endesa Fortaleza (Brazil)		97,314		80,299		17,015		21.2	%
CIEN (Brazil)		35,583		(8,863)		44,446		n.a.
Emgesa (Colombia)		242,490		245,061		(2,571)		(1.0)	%
Edegel (Peru)		181,072		135,187		45,885		33.9	%
Less: Intercompany Transactions		(2,274)		(1,531)		(743)		48.5	%

Total		1,926,178		1,705,652		220,526		12.9	%

Distribution Business
Chilectra and subsidiaries (Chile)		851,363		926,506		(75,143)		(8.1)	%
Edesur (Argentina)		375,344		416,895		(41,551)		(10.0)	%
Edelnor (Peru)		314,945		259,409		55,536		21.4	%
Ampla (Brazil)		900,521		943,612		(43,091)		(4.6)	%
Coelce (Brazil)		675,422		678,458		(3,036)		(0.4)	%
Codensa (Colombia)		643,402		630,025		13,377		2.1	%

Total		3,760,997		3,854,905		(93,908)		(2.4)	%

Less: Consolidation Adjustments and Other Businesses		(606,473)		(591,988)		(14,485)		2.4	%

Total		5,080,702		4,968,569		112,133		2.3	%

Generation and Transmission Business: Operating Costs

The operating costs of Endesa Chile increased Ch$ 121.2 billion, or 14.1%, for the year ended December 31, 2012, mainly as a result of an increase of Ch$ 53.1 billion in fuel consumption costs. This increase in fuel consumption costs was principally a result of greater LNG generation, and Ch$ 31.7 billion greater transportation costs as a consequence of higher tolls related to the drought in the south central area of the country. The cost of energy purchases increased Ch$ 11.3 billion due to higher spot market purchase prices. In addition, depreciation and impairment losses increased Ch$ 20.4 billion for the year ended December 31, 2012 and fixed costs increased Ch$ 16.4 billion. Production decreased 2.5% to 20,194 GWh for the year ended December 31, 2012.

In Argentina, operating costs of Endesa Costanera decreased Ch$ 18.1 billion, or 5.4%, for the year ended December 31, 2012, mainly due to a Ch$ 30.7 billion decrease in procurement and services costs resulting from a Ch$ 27.8 billion decrease in fuel consumption costs and a Ch$ 3.1 billion decrease in transportation costs. This was partially offset by a Ch$ 5.7 billion increase in personnel costs and other fixed costs mainly due to union negotiations and a higher number of employees and a Ch$ 6.9 billion increase in depreciation and impairment losses. Production increased 1.1% to 8,488 GWh for the year ended December 31, 2012. Operating costs of El Chocón decreased 1.1% due to a Ch$ 2.7 billion decrease in procurement and services costs. This decrease is

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primarily the result of a Ch$ 1.6 billion decrease in energy purchases costs and a Ch$ 1 billion decrease in other variable procurement costs, as a consequence of 2,801 GWh generation for the year ended December 31, 2012, a 16.5% increase compared to the year ended December 31, 2011. This was partially offset by a Ch$ 2.1 billion increase in other fixed costs. The effect of currency translation on our Argentine subsidiaries caused an 8.6% decrease of operating costs in Chilean peso terms, compared to the same period of 2011.

In Brazil, the operating costs of Cachoeira Dourada increased 37.7%, or Ch$ 13.7 billion, to Ch$ 50.1 billion for the year ended December 31, 2012. This increase is primarily the result of a Ch$ 11.6 billion increase in procurement and services costs due to a Ch$ 10.8 billion increase in energy purchases costs and a Ch$ 2.9 billion increase in depreciation and impairment losses. Energy generation for the year ended December 31, 2012 reached 3,722.4 GWh, 19.3% more than the previous year. The operating costs of Endesa Fortaleza increased by Ch$ 17 billion for the year ended December 31, 2012, primarily as a result of a Ch$ 16.5 billion increase in procurement and services costs, which in turn was a result of a Ch$ 17.9 billion increase in energy purchases costs and a Ch$ 3.2 billion increase in other variable costs, partially offset by a Ch$ 4 billion decrease in fuel purchases. Energy generation reached 1,454.5 GWh, a 40.7% increase from the year ended December 31, 2011. Operating costs of CIEN increased by Ch$ 44.4 billion, which is primarily the result of a provision reversal for accounts receivable considered not recoverable for Ch$ 20.9 billion for the year ended December 31, 2011 and another amounting to Ch$ 27.8 billion, corresponding to sales tax that did not apply in 2012. The effect of currency translation on our Brazilian companies caused a 13.9% decrease in operating costs in Chilean peso terms, compared to the same period of 2011.

The operating costs of Emgesa decreased Ch$ 2.6 billion or 1.0% for the year ended December 31, 2012, mainly as a result of a Ch$ 40 billion decrease in fixed costs resulting from the non-recurring effect of the equity tax reform driven by the Colombian government during the first trimester of 2011 and which led to a Ch$ 43.5 billion negative effect on Emgesa’s operating result for the year ended December 31, 2012. This was partially offset by a Ch$ 36.2 billion increase in procurement and services costs, due to a Ch$ 19.7 billion increase in costs of energy purchases as a consequence of higher spot market energy purchase prices, and a Ch$ 12.3 billion increase in fuel consumption cost; in addition depreciation, amortization and impairment losses increased Ch$ 1.2 billion. Energy generation reached 13,294 GWh in 2012, which represents a 10% increase when compared to 2011, which increase was mainly attributable to increased hydroelectric generation. The effect of currency translation caused a 3.4% increase in operating costs in Chilean peso terms, compared to the same period of 2011.

Operating costs of Edegel increased Ch$ 45.9 billion, or 33.9%, mainly as a consequence of Ch$ 15.2 billion greater personnel costs due to the one time effect of a provision reversal registered in 2011 of Ch$ 14.6 billion in personnel expenses. Additionally, energy purchase costs increased Ch$ 14.7 billion as a result of greater spot market electricity purchases, along with Ch$ 6.1 billion greater fuel consumption costs, partially due to greater diesel generation, in both cases as the result of maintenance performed to the dual gas units. Transportation costs increased by Ch$ 3.3 billion and depreciation, amortization and impairment losses increased by Ch$ 2.2 billion. Energy generation fell 4.5% to 8,740.3 GWh for the year ended December 31, 2012. The effect of currency translation caused a 5.0% increase in costs in Chilean peso terms, compared to the same period of 2011.

Distribution Business: Operating Costs

The operating costs of Chilectra decreased Ch$ 75.1 billion, or 8.1%, for the year ended December 31, 2012, due to a Ch$ 75.9 billion decrease in procurement and services costs. This decrease was primarily the result of a Ch$ 85.4 billion decrease in energy purchases partially offset by a Ch$ 7 billion increase in transportation costs and a Ch$ 2.6 billion increase in other variable costs. Physical energy losses decreased by 0.1 percentage points to 5.4% for the year ended December 31, 2012.

The operating costs of Edesur decreased Ch$ 41.6 billion, or 10.0%, for the year ended December 31, 2012. This decrease is principally the result of a Ch$ 105.7 billion decrease in depreciation, amortization and impairment losses because a Ch$ 106.5 billion impairment loss related to Property, Plant and Equipment was booked during the fourth quarter of 2011, which almost covers the total amount of equity risk that this company represents for Enersis. This decrease was partially offset by a Ch$ 33.5 billion increase in procurement and services costs that was primarily the result of an increase in energy purchase costs. Higher energy purchase costs in turn resulted from a higher average purchase price and an increase in electricity purchases. Additionally, fixed operating costs increased by Ch$ 30.6 billion, due to an increase in wage costs caused by inflation, the entry into agreements with union employees and an increase in other fixed costs of contracted procurement and services which have experienced an overall price increase due to inflation. Edesur’s negative operating performance was attributable to an increase in operating costs as a result to inflation in Argentina, without a corresponding tariff increase due to delays by the Argentine Government in complying with certain obligations contained in Edesur’s agreement with the Argentine Government. This non-compliance primarily consists of failure to observe the cost monitoring mechanism set forth in the agreement, which requires recognition of tariff adjustments every six months and the performance of an overall tariff revision. Physical energy losses increased by 0.1 percentage points to 10.6% for the year ended December 31, 2012. The effect of currency translation caused an 8.6% decrease in operating costs in Chilean peso terms, compared to the same period of 2011.

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The operating costs of Edelnor increased Ch$ 55.5 billion, or 21.4%, for the year ended December 31, 2012, mainly due to a Ch$ 41.1 billion increase in procurement and services costs, as a consequence of a Ch$ 40 billion increase in energy purchase costs and Ch$ 1.1 billion in other variable costs. Additionally, personnel costs increased by Ch$ 8.3 billion mainly due to a Ch$ 5.4 billion one time reversal of a personnel expense provision booked in 2011. Physical energy losses remained stable at 8.2% for the year ended December 31, 2012. The effect of currency translation caused a 5.0% increase in operating costs in Chilean peso terms, compared to the same period of 2011.

In Brazil, the operating costs of Ampla decreased Ch$ 43.1 billion, or 4.6%, for the year ended December 31, 2012. This decrease was primarily the result of a Ch$ 50.8 billion decrease in procurement and services costs, which decrease resulted from a Ch$ 50 billion decrease in energy purchase costs and a Ch$ 37 billion decrease in other variable procurement costs, partially offset by a Ch$ 36.1 billion increase in transportation costs. Additionally, fixed costs decreased by Ch$ 10.2 billion, partially offset by a Ch$ 17.9 billion increase in depreciation, amortization and impairment losses costs. Physical energy losses decreased by 0.1 percentage points to 19.6% for the year ended December 31, 2012. The operating costs of Coelce decreased by Ch$ 3 billion, or 0.4%, for the year ended December 31, 2012. This decrease is primarily the result of a Ch$ 5 billion decrease in depreciation, amortization and impairment losses, partially offset by a Ch$ 1.3 billion increase in procurement and services costs resulting from a Ch$ 14.1 billion increase in energy purchases, partly offset by a Ch$ 12.5 billion decrease in other variable costs. Physical energy losses increased by 0.7 percentage points to 12.6% for the year ended December 31, 2012. For both Ampla and Coelce, the effect of currency translation caused a 13.9% reduction in operating costs in Chilean peso terms, compared to the same period of 2011.

Operating costs of Codensa increased by Ch$ 13.4 billion, or 2.1%, for the year ended December 31, 2012. This increase was primarily the result of a Ch$ 29.2 billion increase in procurement and services costs, primarily explained by a Ch$ 23.1 billion increase in energy purchases, a Ch$ 2.2 billion increase in energy transportation costs and a Ch$ 3.9 billion increase in other variable procurement cost. This was partially offset by a Ch$ 20.3 billion decrease in fixed costs related to the non-recurring effect of the Colombian Government’s equity tax reform promulgated in 2011, which caused a Ch$ 28.6 billion negative impact on operating results for the year ended December 31, 2011, but did not affect Codensa’s results for the year ended December 31, 2012. Physical energy losses decreased by 0.6 percentage points to 7.5% for the year ended December 31, 2012. The effect of currency translation caused a 3.4% increase in operating costs in Chilean peso terms, compared to the same period of 2011.

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Operating Income

The following table summarizes operating income by company for the years ended December 31, 2012 and 2011.


	Year ended December 31,
	2012		2011		Change		% Change
	(in million of Ch$)
Generation and Transmission Business
Endesa and subsidiaries (Chile)		175,752		398,804		(223,052)		(55.9)	%
Endesa Costanera (Argentina)		(22,088)		6,480		(28,568)		n.a.
El Chocón (Argentina)		24,865		23,742		1,123		4.7	%
Cachoeira Dourada (Brazil)		105,124		90,281		14,843		16.4	%
Endesa Fortaleza (Brazil)		41,872		49,186		(7,314)		(14.9)	%
CIEN (Brazil)		36,940		68,781		(31,841)		(46.3)	%
Emgesa (Colombia)		337,661		253,508		84,153)		33.2	%
Edegel (Peru)		101,052		104,655		(3,603)		(3.4)	%
Less: Intercompany Transactions		(93)		(1,063)		970		(91.3)	%

Total		801,085		994,374		(193,289)		(19.4)	%

Distribution Business
Chilectra and subsidiaries (Chile)		133,375		119,685		13,690		11.4	%
Edesur (Argentina)		(54,102)		(137,170)		83,068		60.6	%
Edelnor (Peru)		70,068		69,900		168		0.2	%
Ampla (Brazil)		173,716		173,657		59		0.0	%
Coelce (Brazil)		131,005		180,988		(49,983)		(27.6)	%
Codensa (Colombia)		245,184		185,462		59,722		32.2	%

Total		699,246		592,522		106,724		18.0	%

Less: Consolidation Adjustments and Other Businesses		(3,366)		(20,585)		17,219		(83.6)	%

Total		1,496,965		1,566,311		(69,346)		(4.4)	%

Non-Operating Results

The following table shows the non-operating results for the years ended December 31, 2012 and 2011.


	Year ended December 31,
	2012		2011		Change		% Change
	(in million of Ch$)
Financial result
Financial income		264,709		233,613		31,096		13.3	%
Financial costs		(453,447)		(465,411)		11,964		2.6	%
Gain (loss) for indexed assets and liabilities		(12,682)		(25,092)		12,410		49.5	%
Net foreign currency exchange differences		(14,769)		20,305		(35,074)		n.a.

Total		(216,189)		(236,585)		20,396		8.6	%

Other non-operating results
Total gain (loss) on sale of non-current assets not held for sale		14,094		(5,853)		19,947		n.a.
Other non-operating income		10,583		9,504		1,079		11.4	%

Total		24,677		3,651		21,026		n.a.

Non-operating results		(191,512)		(232,934)		41,422		17.8	%

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Financial Result

The total financial result for the year ended December 31, 2012 was a Ch$ 216.2 billion expense, which represents an 8.6% reduction, or Ch$ 20.4 billion, when compared to 2011. The above is primarily the result of:

Financial income increased Ch$ 31.1 billion as a result of the valuation of the current value of non-amortized assets at the concession expiration date of Ampla and Coelce based on the net replacement value of electricity assets depreciated by Ch$ 112.3 billion, partially offset by (1) a decrease in the current value of Cachoeira Dourada’s accounts receivables from CELG Distribuiçao S.A. of Ch$ 24.3 billion, (2) a Ch$ 15 billion decrease in income from cash deposits, (3) a Ch$ 10 billion decrease in income from pension plan assets in Brazil, (4) a decrease in income from Endesa Eco related to the value of the put option of Canela equivalent to Ch$ 6.6 billion and (5) a decrease in financial income of Endesa Costanera due to the Ch$ 2.6 billion accounts receivable from CAMMESA.

Financial expenses decreased Ch$ 12 billion mainly due to (1) a Ch$ 20.6 billion decrease in financial expenses of CIEN, caused by a lower level of average debt during the period and lower current value of fines imposed, (2) a Ch$ 19.4 billion decrease in financial expenses of Ampla due to a lower current value of contingencies, (3) a Ch$ 9.6 billion decrease in financial expenses of Endesa Fortaleza and (4) a Ch$ 7.5 billion decrease in financial expenses of Investluz, in both cases due to lower current value of contingencies for the year ended December 31, 2012. The aforementioned is partially offset by a Ch$ 24.3 billion increase in financial expenses of Coelce due to the current value of litigations and fines imposed and a Ch$ 20.5 billion increase in financial expenses of Edesur due to greater interest expenses on loans and accounts payable to CAMMESA.

Expenses per adjustment units declined Ch$ 12.4 billion due to the impact of the change in value of the UF on the debt, denominated in UF, that some companies have in Chile. This is due to a 2.5% increase in the value of the UF for the year ended December 31, 2012 compared to a 3.9% increase for the year ended December 31, 2011.

These amounts were partially offset by greater currency exchange differences, which increased Ch$ 35.1 billion mainly due to (1) a Ch$ 7.6 billion loss caused by exchange rate variations on cash and cash equivalents, (2) a Ch$ 19.1 billion loss related to accounts receivables and other receivables in U.S. dollars and (3) a Ch$ 9 billion loss in other non-financial assets.

Result of Asset Sales

The result from asset sales led to a positive variation of Ch$ 20 billion, mainly explained by booking a Ch$ 10.7 billion loss in 2011 related to the sale of our electrical parts procurement business, Compañía Americana de Multiservicios Ltda. (CAM), and Synapsis Soluciones y Servicios IT Ltda. and Ch$ 5.7 billion greater income from the sale of real property of Coelce and of Inmobiliaria Manso de Velasco in 2012.

The total non-operating result therefore showed a decrease of Ch$ 41.4 billion over the same period of the previous year.

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Net Income

The following table sets forth our net income for the periods indicated.


	Year ended December 31,
	2012		2011		Change			% Change
	(in million of Ch$)
Operating income		1,496,965		1,566,311		(69,346	)		(4.4)	%
Non-operating results		(191,512)		(232,934)		41,422			(17.8)	%

Net income before taxes		1,305,453		1,333,377		(27,924)			(2.1)	%

Income tax		(411,891)		(460,837)		48,946			(10.6)	%

Net Income from Continuing Operations After Tax		893,562		872,540		(21,022)			(2.4)	%

Net income from discontinued operations		0		0		0			0.0	%


Net Income		893,562		872,540		(21,022)			(2.4)	%

Net Income attributable to: Shareholders of Enersis		377,351		375,471		1,880			0.5	%

Net income attributable to: Non-controlling interests		516,211		497,069		19,142			3.9	%

Corporate Income Tax

Income tax declined Ch$ 49 billion, primarily as a result of (1) a Ch$ 61 billion decrease in taxes of Endesa Chile, (2) a Ch$ 16.4 billion decrease in taxes of Endesa Costanera, (3) a Ch$ 15.2 billion decrease in taxes of Edesur, (4) a Ch$ 19.2 billion decrease in taxes of Enersis, (5) a Ch$ 10.3 billion decrease in taxes of Cachoeira Dourada, (6) a Ch$ 9.7 billion decrease in taxes of San Isidro, (7) a Ch$ 7.5 billion decrease in taxes of Coelce, (8) a Ch$ 8.4 billion decrease in taxes of CIEN, and (9) a Ch$ 8.8 billion decrease in taxes of Chilectra. These amounts were partially offset by (1) a Ch$ 43.8 billion increase in taxes of Pehuenche, (2) a Ch$ 16.9 billion increase in taxes of Emgesa, (3) a Ch$ 9.7 billion increase in taxes of Codensa and (4) a Ch$ 3.5 billion increase in taxes of Edegel.

3.	Results of Operations for the Years ended December 31, 2011 and December 31, 2010

Net income in 2011 decreased 20.7%, from Ch$ 1,100.7 billion in 2010 to Ch$ 872.5 billion in 2011. This decrease of Ch$ 228.1 billion is attributable primarily to the accounting impairment recorded in our books in connection with our Argentine subsidiaries, Edesur and Endesa Costanera, coupled with an increase in income tax. The decrease in net income attributable only to shareholders of Enersis (excluding the decrease in net income attributable to non-controlling interests) amounted to Ch$ 110.8 billion.

In 2011, we recorded an impairment loss in Property, Plant and Equipment of Ch$ 106.4 billion attributable to our operating costs in Edesur, an impairment in tax credits of Ch$ 44.9 billion for Edesur and Endesa Costanera, and a goodwill impairment of Ch$ 14.4 billion associated with our acquisitions of Edesur and Endesa Costanera.

We implemented the impairment loss in connection with Edesur due to the sustained period of uncertainty in the Argentine electricity sector as to whether distribution tariff adjustments would be carried out by Argentine regulatory authorities to reflect our increased costs in providing electricity service. Since the enactment of Argentina’s Public Emergency Law in 2002, our costs of providing electricity service have been subject to significant increases, without adequate tariff increases. Although Edesur did receive an increase in VAD in 2007, ENRE has not allowed much higher operating costs in 2010 and 2011 to be passed through to final tariffs.

Since 2007, increases in tariffs have not occurred due to delays in fulfillment of requirements of the Agreement Act signed between the Republic of Argentine and Edesur in August 2005, particularly with regards to the semi-annual recognition of tariff adjustments under the cost monitoring mechanism and the implementation of the integral tariff review, each as prescribed in the Agreement Act, the absence of which are severely affecting Edesur’s viability as a going concern. Given the already long period during which tariff adjustments had not been made, and our assessment of the prospects of any future tariff adjustments, at the end of 2011 we recorded the impairment loss and reversal of goodwill related to Edesur.

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In connection with Endesa Costanera, our impairment loss was attributable to the inability to obtain revenues which would allow a recovery of costs and to a sustained working capital deficit over a very long period. In addition, our Argentine generator has encountered difficulties in obtaining the timely payment of receivables from CAMMESA, the operator of the Argentine electricity market. This situation affected Endesa Costanera’s viability as a going concern.

Additionally, we incurred Ch$ 70 billion in higher income taxes (excluding impairment on tax credits mentioned above).

The order in which the countries are ranked in these tables is according to their contribution to our 2011 operating income.

Revenues

Generation and Transmission Business

The following table sets forth the electricity sales of our subsidiaries and their corresponding changes for the twelve-month periods ended on December 31, 2011 and 2010.


	Electricity sales during (GWh) Year ended December 31,
	2011		2010		Change		% Change
Endesa Chile (Chile) (1)		22,070		21,847		222		1.0	%
Emgesa (Colombia)		15,112		14,817		295		2.0	%
Edegel (Peru)		9,450		8,598		851		9.9	%
Cachoeira Dourada (Brazil)		3,986		3,833		153		4.0	%
Endesa Fortaleza (Brazil)		2,842		2,957		(115)		(3.9)	%
El Chocón (Argentina)		2,888		3,361		(473)		(14.1)	%
Endesa Costanera (Argentina)		8,493		8,018		476		5.9	%

Total		64,840		63,431		1,409		2.2	%

(1)	Includes Endesa Chile and its generation subsidiaries.

Distribution Business

Distribution revenues are derived mainly from the resale of electricity purchased from generators. Revenues associated with distribution include the recovery of the cost of electricity purchased and the resulting revenue from the VAD, which is associated with the recovery of costs and the return on the investment with respect to the distribution assets plus the losses permitted in the regulatory tariffs. Other revenue deriving from our distribution services consists of charges related to new connections and the maintenance and rental of meters.

The following table sets forth the electricity sales of our subsidiaries, by country, and their corresponding variations for the years ended December 31, 2011 and 2010.


	Electricity sales during (GWh) Year ended December 31,
	2011		2010		Change		% Change
Codensa (Colombia) (1)		12,857		12,515		342		2.7	%
Coelce (Brazil)		8,970		8,850		120		1.4	%
Ampla (Brazil)		10,223		9,927		296		3.0	%
Chilectra (Chile)		13,697		13,098		599		4.6	%
Edelnor (Peru)		6,572		6,126		446		7.3	%
Edesur (Argentina)		17,233		16,759		474		2.8	%

Total		69,552		67,274		2,278		3.4	%

(1)	Values for Codensa include the proportional consolidation of 49.0% of DECSA. This consolidation also affects other figures in this section, such as operating income, revenues, operating costs and number of clients.

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Revenues by Business Segment

The table below presents our revenues for 2011 and 2010:


	Year ended December 31,
	2011		2010		Change		% Change
	(in million of Ch$)
Generation and Transmission Business
Endesa Chile and subsidiaries (Chile)		1,257,995		1,345,371		(87,376)		(6.5)	%
Emgesa (Colombia)		498,569		507,527		(8,958)		(1.8)	%
Edegel (Peru)		239,842		211,263		28,579		13.5	%
Cachoeira Dourada (Brazil)		126,646		115,663		10,983		9.5	%
CIEN (Brazil)		59,918		98,909		(38,991)		(39.4)	%
Endesa Fortaleza (Brazil)		129,485		150,371		(20,886)		(13.9)	%
El Chocón (Argentina)		48,341		57,173		(8,832)		(15.4)	%
Endesa Costanera (Argentina)		341,824		295,231		46,593		15.8	%
Less: Intercompany Transactions		(2,594)		(904)		(1,690)		186.9	%

Total		2,700,026		2,780,604		(80,578)		(2.9)	%

Distribution Business
Codensa (Colombia)		815,487		785,890		29,597		3.8	%
Coelce (Brazil)		859,446		940,654		(81,208)		(8.6)	%
Ampla (Brazil)		1,117,269		1,046,387		70,882		6.8	%
Chilectra and subsidiaries (Chile)		1,046,191		1,016,997		29,194		2.9	%
Edelnor (Peru)		329,309		307,159		22,150		7.2	%
Edesur (Argentina)		279,725		295,539		(15,814)		(5.4)	%

Total		4,447,427		4,392,626		54,801		1.2	%

Less: Consolidation Adjustments and Other Businesses		(612,573)		(609,649)		(2,924)		0.5	%

Total		6,534,880		6,563,581		(28,701)		(0.4)	%

Generation and Transmission Business: Revenues

Revenues in Chile in 2011 decreased by 6.5%, mainly due to lower energy sales, principally due to a lower average sale price, partially offset by larger electricity sales which increased by 1.0%, reaching 22,070 GWh in 2011.

In Colombia, revenues of Emgesa decreased by Ch$ 9.0 billion, or 1.8%, principally due to a 4.0% reduction in the average energy sale price which was partially offset by an increase in electricity sales of 2.0% as a consequence of higher hydroelectric generation, totaling 15,112 GWh. The “currency translation effect” (from translating local Colombian pesos into Chilean pesos) on revenues was negative, causing a decline of 2.6% in peso terms.

Revenues of Edegel, our Peruvian generating company, increased by Ch$ 28.6 billion, or 13.5%, in 2011 This was principally the result of a 9.9% growth in electricity sales, totaling 9,450 GWh in 2011, as well as an increase in the average energy sale price for 2011. The currency translation effect on revenues was negative, causing a decline of 2.7% in peso terms.

Revenues of Cachoeira Dourada rose by 9.5% in 2011, mainly as a result of an increase in average sales prices, expressed in local currency, and an increase in electricity sales of 153 GWh, to 3,986 GWh, for the year.

Revenues of CIEN fell by 39.4% in 2011, mainly due to the fact that the Annual Permitted Revenue (APR) was booked since mid April. The APR remunerates the company’s transmission assets, causing lower revenues than the energy-export revenues to Argentina generated during 2010.

Revenues of Endesa Fortaleza decreased by 13.9% in 2011, mainly due to lower sales prices and a reduction in electricity sales of 115 GWh, to 2,842 GWh. In our Brazilian companies, the currency translation effect on revenues was negative, causing a slight decline of 0.2% in peso terms, in comparison to 2010.

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In Argentina, revenues of Endesa Costanera rose by 15.8% in 2011, principally as a result of an increase in electricity sales and higher average prices. Electricity sales reached 8,493.3 GWh in 2011 compared to 8,017.7 GWh in 2010.

Revenues of El Chocón fell by 15.4% in 2011, explained by a decrease in generation of 19.2% compared to 2010, due to lower hydroelectric availability, which in turn was a result of reservoir controls at levels limited by each river basin. For both Argentine companies, the net effect of translating results from the Argentine peso to the Chilean peso was negative, resulting in a 10.1% decline in revenues in peso terms.

Distribution Business: Revenues

In Colombia, revenues of our subsidiary Codensa increased by 3.8%, mainly as result of a 3.6% increase in the average sale price in local currency, a 2.7% increase in electricity sales to 12,857 GWh, and increases in other operating revenues, which rose by Ch$ 3.9 billion. This was partially offset by the currency translation effect, which resulted in a decline in revenues of 2.6% as expressed in peso terms. The number of customers rose by 70,357, for an aggregate total of over 2.6 million.

In Brazil, revenues of Coelce decreased by 8.6% in 2011, mainly due to a 6.1% drop in the average sale price in local currency, a reduction of Ch$ 98.1 billion in revenues due to the construction of fixed assets in the concession area and the currency translation effect which resulted in a fall of revenues of 0.2% in peso terms. This was partially offset by a 1.4% rise in electricity sales to 8,970 GWh in 2011. The number of customers rose by 129,778 in 2011, for an aggregate total of over 3.2 million.

Revenues of our subsidiary Ampla rose by 6.8% in 2011, mainly due to a 3.0% increase in electricity sales (to 10,223 GWh), a 2.2% increase in the average sale price in local currency, and an increase in other operating revenues of Ch$ 21.0 billion. This was partially offset by the currency translation effect, which resulted in a decline of revenues of 0.2% in peso terms. The number of customers rose by 72,881, for an aggregate total exceeding 2.6 million.

In Chile, revenues of our subsidiary Chilectra increased by Ch$ 29.2 billion or 2.9% in 2011, principally due to greater electricity demand, which was reflected by a 4.6% increase in electricity sales (reaching 13,697 GWh in 2011). This was partially offset by a slight decrease of 0.6% in the average sale price and a Ch$ 3.2 billion decrease in other operating revenues. The number of customers rose by 28,325, reaching an aggregate total of over 1.6 million.

In Peru, revenues of Edelnor increased by 7.2% in 2011, due to a 7.3% increase in electricity sales to 6,572 GWh and an 8.6% increase in average sales prices in local currency. This was partially offset by a decrease of Ch$ 3.2 billion in other operating revenues and the currency translation effect which resulted in a decline of revenues of 2.7% in 2011 in peso terms. The number of customers rose by 46,501, to an aggregate total exceeding 1.1 million.

In Argentina, revenues of Edesur decreased by 5.4% in 2011 due mainly to the currency translation effect that resulted in a decrease in revenues of 10.1% in peso terms. This was partially offset by a 2.8% increase in electricity sales and a Ch$ 0.5 billion increase in other operating revenues. Average sale prices in local currency remained the same as in 2010, as well as physical energy losses, at a level of 10.5%. The number of customers rose by 35,885, to an aggregate total of almost 2.4 million.

Operating Costs

Operating costs primarily consist of electricity purchases from other parties, fuel purchases, depreciation, amortization and impairment losses, maintenance costs, tolls paid to transmission companies, and employee salaries. Operating costs also include Administrative and Selling expenses.

The following table shows the breakdown of operating costs as a percentage of total operating costs, for the years ended December 2011 and 2010. As can see it, the cost structure of the Company was virtually the same in 2011 and 2010.

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	Year ended December 31
	2011			2010
	(percentage of total costs of operations)
Electricity purchases		35.5	%		32.0	%
Fuel purchases		14.9	%		13.8	%
Other variable cost		12.9	%		18.3	%
Depreciation, amortization and impairment losses		11.3	%		11.5	%
Other fixed costs		10.9	%		9.3	%
Transmission tolls		7.9	%		8.4	%
Staff benefit costs		6.6	%		6.8	%

		100	%		100	%

The table below sets forth the breakdown of operating costs for the years ending on December 31, 2011 and 2010:


	Year ended December 31,
	2011		2010		Change		% Change
	(in million of Ch$)
Generation and Transmission Business
Endesa Chile and subsidiaries (Chile)		859,191		832,601		26,590		3.2	%
Emgesa (Colombia)		245,061		246,044		(983)		(0.4)	%
Edegel (Peru)		135,187		140,944		(5,757)		(4.1)	%
Cachoeira Dourada (Brazil)		36,365		39,800		(3,435)		(8.6)	%
CIEN (Brazil)		(8,863)		70,853		(79,716)		(112.5)	%
Endesa Fortaleza (Brazil)		80,299		91,257		(10,958)		(12.0)	%
El Chocón (Argentina)		24,599		25,522		(923)		(3.6)	%
Endesa Costanera (Argentina)		335,344		284,391		50,953		17.9	%

Less: Intercompany Transactions		(1,531)		(902)		(629)		69.7	%

Total		1,705,652		1,730,510		(24,858)		(1.4)%

Distribution Business
Codensa (Colombia)		630,025		578,667		51,358		8.9	%
Coelce (Brazil)		678,458		757,490		(79,032)		(10.4)	%
Ampla (Brazil)		943,612		925,698		17,914		1.9	%
Chilectra and Subsidiaries (Chile)		926,506		905,231		21,275		2.4	%
Edelnor (Peru)		259,409		242,210		17,199		7.1	%
Edesur (Argentina)		416,895		291,595		125,300		43.0	%

Total		3,854,905		3,700,891		154,014		4.2	%

Less: Consolidation Adjustments and Other Businesses		(591,988)		(572,121)		(19,867)		3.5	%

Total		4,968,569		4,859,280		109,289		2.2	%

Generation and Transmission Business: Operating Costs

Operating costs in Chile increased by 3.2% in 2011 compared to 2010, totaling Ch$ 859.2 billion. Lower hydroelectric generation forced the company to use thermal energy more intensively, and this caused the procurement and services costs to increase by 2%, or Ch$ 13.4 billion, with higher energy purchases costs of Ch$ 66.3 billion and fuel consumption costs of Ch$ 32.1 billion, partially offset by lower transport expenses of Ch$ 46.1 billion and other variable costs of Ch$ 38.9 billion. In addition, personnel expenses rose by Ch$ 7.3 billion and depreciation, amortization and impairment losses by Ch$ 3.8 billion. Production totaled 20,722 GWh, 0.9% lower than in 2010.

Operating costs of Emgesa decreased by Ch$ 1.0 billion, or 0.4%, mainly due to reduced energy purchases of Ch$ 43.3 billion and reduced fuel costs of Ch$ 3.8 billion. This was partially offset by higher fixed costs, which resulted from the one-time effect of the equity tax reform of Ch$ 40.2 billion (which required the booking of the entire amount of this tax payable for the four year period 2011-2014 on January 1, 2011) added to increased transport costs of Ch$ 4.0 billion, other variable costs of Ch$ 1.3 billion and a higher charge for depreciation, amortization and impairment of Ch$ 0.7 billion associated with the increase in generation of 7.2% to 12,090 GWh in 2011. The currency translation effect resulted in a 2.6% decrease in operating costs in peso terms.

123

Edegel declined by Ch$ 5.8 billion, or 4.1%, largely due to a reduced personnel expenses of Ch$ 8.8 billion, reduced energy purchase costs of Ch$ 1.7 billion and a reduced charge for depreciation, amortization and impairment of Ch$ 1.5 billion. This was partially offset by an increase in fuel costs of Ch$ 3.9 billion, resulting from an increase of energy generation of 8.1% to 9,153 GWh. The currency translation effect resulted in a reduction of 2.7% in the operating costs expressed in peso terms.

Operating costs of Cachoeira Dourada decreased by 8.6%, or Ch$ 3.4 billion, to Ch$ 36.4 billion in 2011, mainly due to reduced costs for impairment losses of Ch$ 3.9 billion following the reaching of an agreement with CELG Distribução S.A. to reverse an account payable provision, which was partially offset by increased transport costs of Ch$ 0.4 billion and a rise in personnel expenses of Ch$ 0.1 billion. Generation reached 3,121 GWh in 2011, a fall of 9.0% compared to 2010.

Operating costs of CIEN fell by Ch$ 79.7 billion in 2011, a decrease greater than the total of costs for 2010. This is due to lower procurement and services costs of Ch$ 41.5 billion (largely due to the reversal on the transport tolls taxes provision) and a lower charge for depreciation, amortization and impairment of Ch$ 36.7 billion (such decrease due to the fact that depreciation was adjusted to the useful lives of the assets of the concession period in 2010). The currency translation effect resulted in a reduction of 0.2% in the operating costs expressed in peso terms.

Operating costs of Endesa Fortaleza fell by Ch$ 11.0 billion in 2011, or 12.0%, mainly due to lower energy purchase costs of Ch$ 4.7 billion, lower fuel purchase costs of Ch$ 1.8 billion and a decrease in other variable costs of Ch$ 4.8 billion. Generation reached 1,033 GWh in 2011, a fall of 37.9% from the prior year, due to a lower dispatch. The currency translation effect in both Brazilian companies resulted in a reduction of 0.2% in the cost of sales expressed in peso terms.

Operating costs of our subsidiary El Chocón declined by Ch$ 0.9 billion in 2011, or 3.6%. This was mainly due to a decrease in other variable costs of Ch$ 1.6 billion, partially offset by an increase in the cost of energy purchases of Ch$ 0.8 billion. Generation reached 2,404 GWh in 2011, a fall of 19.2% compared to the prior year. The currency translation effect resulted in a reduction of 10.1% in the cost of sales expressed in peso terms.

Operating costs of Endesa Costanera rose by Ch$ 51.0 billion in 2011, or 17.9%. This was mainly due to an increase in procurement and services costs of Ch$ 48.5 billion, or 19.4%, (such increase largely due to a higher cost of fuel consumption of Ch$ 40.2 billion) and higher transport expenses of Ch$ 4.4 billion resulting from a 5.4% increase in production to 8,397 GWh in 2011. Personnel expenses rose by Ch$ 4.4 billion, partially offset by a reduction in the charge for depreciation, amortization and impairment of Ch$ 1.1 billion and a reduction in other fixed costs of Ch$ 0.8 billion. The currency translation effect resulted in a reduction of 10.1% in the cost of sales expressed in peso terms.

Distribution Business: Operating Costs

Operating costs of Codensa increased by Ch$ 51.4 billion, or 8.9%, in 2011, mainly due to higher energy purchase costs of Ch$ 20.6 billion, higher fixed costs due to the impact of an equity tax reform charge of Ch$ 19.7 billion, which required booking the entire amount of the tax payable for the four year period (2011-2014) on January 1, 2011, higher variable costs of Ch$ 3.4 billion and higher personnel expenses of Ch$ 2.5 billion. Physical energy losses fell by 0.4 percentage points to 8.1% in 2011. The currency translation effect resulted in an increase of 2.6% in the cost of sales expressed in peso terms.

Operating costs of Coelce decreased by Ch$ 79.0 billion, or 10.4%, in 2011. This is mainly due to a decrease in other variable costs of Ch$ 96.8 billion (due to a reduction in fixed asset construction costs in the concession area) and a reduced charge for depreciation, amortization and impairment of Ch$ 6.3 billion. This is partially offset by an increase in energy purchase costs of Ch$ 26 billion and personnel expenses of Ch$ 4 billion. Physical energy losses fell by 0.2 percentage points to 11.9% in 2011. In each of Ampla and Coelce, the currency translation effect resulted in a reduction of 0.2% in the cost of sales expressed in peso terms.

Operating costs of our subsidiary Ampla grew by Ch$ 17.9 billion, or 1.9% in 2011. This is mainly due to increases in the cost of energy purchases of Ch$ 34.8 billion, in other operating costs of Ch$ 18.3 billion (primarily due to the construction of fixed assets in the concession area, for Ch$ 18.0 billion), in transport costs of Ch$ 10.3 billion and in personnel expenses of Ch$ 2.0 billion. This was partially offset by a decrease in the charge for depreciation, amortization and impairment of Ch$ 48.7 billion, primarily due to impairment losses booked in 2010. Physical energy losses fell by 0.8 percentage points to 19.7% in 2011.

Operating costs of Chilectra increased by Ch$ 21.3 billion, or 2.4%, in 2011, mainly due to increases in energy purchase costs of Ch$ 9.2 billion, transport costs of Ch$ 7.2 billion, and personnel expenses of Ch$ 4.7 billion, in addition to a charge for depreciation, amortization and an impairment of Ch$ 4.6 billion associated with Chilectra’s investment in Edesur. This was partially offset by a reduction in other fixed operating costs of Ch$ 3.8 billion, which was associated with reduced repairs, conservation and other activities. Electricity sales declined by 0.3 percentage points to 5.5% in 2011.

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Operating costs of Edelnor increased by Ch$ 17.2 billion, or 7.1% in 2011, mainly due to an increase in energy purchases of Ch$ 20.4 billion and a higher charge for depreciation, amortization and impairment of Ch$ 1.0 billion. This was partially offset by a reduction in other variable costs of Ch$ 3.2 billion and a reduction in personnel costs of Ch$ 1.1 billion. Physical energy losses decreased by 0.1 percentage points to 8.2%. The currency translation effect resulted in a decrease of 2.7% in the operating costs expressed in peso terms.

Operating costs of Edesur increased by Ch$ 125.3 billion, or 43.0% in 2011. This is primarily due to an impairment loss of Ch$ 106.5 billion taken at the Enersis level at the end of 2011 in connection with Edesur’s property, plant and equipment. This impairment loss is a result of the inadequate distribution tariff adjustments allowed for our Argentine subsidiary. Since the Argentine Public Emergency Law of 2002, our operating costs have been subject to significant inflationary pressures, without any corresponding tariff increases. Increases in tariffs have not occurred due to delays in the fulfillment of certain requirements of the Agreement Act executed by Edesur and the Republic of Argentina, particularly with regard to the semi-annual recognition of tariff adjustments under the cost monitoring mechanism and the implementation of an integral tariff review contemplated by the Agreement Act, the absence of which are severely affecting Edesur’s viability as a going concern. Additionally, personnel expenses increased by Ch$ 20.0 billion and other fixed costs increased by Ch$ 1.1 billion. In contrast, other variable costs declined by Ch$ 0.6 billion and the charge for depreciation fell by Ch$ 1.0 billion. Physical energy losses remained at 10.5% for both 2010 and 2011. The currency translation effect resulted in a reduction of 10.1% in the operating costs expressed in peso terms.

Operating Income

The following table summarizes operating income by company, for the years ended December 31, 2011 and 2010:


	Year ended December 31,
	2011		2010		Change		% Change
	(in million of Ch$)
Generation and Transmission Business
Endesa Chile and subsidiaries (Chile)		398,804		512,770		(113,966)		(22.2)	%
Emgesa (Colombia)		253,508		261,483		(7,975)		(3.0)	%
Edegel (Peru)		104,655		70,319		34,336		48.8	%
Cachoeira Dourada (Brazil)		90,281		75,863		14,418		19.0	%
CIEN (Brazil)		68,781		28,056		40,725		145.2	%
Endesa Fortaleza (Brazil)		49,186		59,114		(9,928)		(16.8)	%
El Chocón (Argentina)		23,742		31,651		(7,909)		(25.0)	%
Endesa Costanera (Argentina)		6,480		10,840		(4,360)		(40.2)	%

Less: Intercompany Transactions		(1,063)		(2)		(1,061)		N/A

Total		994,374		1,050,094		(55,720)		(5.3)	%

Distribution Business
Codensa (Colombia)		185,462		207,223		(21,761)		10.5	%
Coelce (Brazil)		180,988		183,164		(2,176)		(1.2)	%
Ampla (Brazil)		173,657		120,689		52,968		43.9	%
Chilectra and subsidiaries (Chile)		119,685		111,766		7,919		7.1	%
Edelnor (Peru)		69,900		64,949		4,951		7.6	%
Edesur (Argentina)		(137,170)		3,944		(141,114)		N/A

Total		592,522		691,735		(99,213)		(14.3)	%

Less: Consolidation Adjustments and Other Businesses		(20,585)		(37,528)		16,943		(45.1)	%

Total		1,566,311		1,704,301		(137,990)		(8.1)	%

125

Non-Operating Results

The following table shows the non-operating results for the years ended December 31, 2011 and 2010:


	Year ended December 31,
	2011			2010			Change			% Change
	(in million of Ch$)
Financial result
Financial income		233,613			171,237			62,376			36.4	%
Financial costs		(465,411	)		(438,358	)		(27,053	)		(6.2	)%
Gain (loss) for indexed assets and liabilities		(25,092	)		(15,056	)		(10,036	)		(66.7	)%
Net Foreign currency exchange differences		20,305			11,572			8,733			75.5	%

Total		(236,585	)		(270,605	)		34,020			(12.6	)%

Other non-operating results
Total gain (loss) on sale of non-current assets not held for sale		(5,853			11,711	)		(17,564	)		n.a.
Other non-operating income		9,504			1,288			8,216			637,9	%

Total		3,651			12,999			(9,348	)		(71.9	)%

Non-operating results		(232,934	)		(257,606	)		24,672			(9.6	)%

Financial Result

Total financial result for the year 2011 was an expense of Ch$ 236.6 billion, a decrease of 12.6%, or Ch$ 34.0 billion, in comparison to 2010. This is due to higher financial income of Ch$ 62.4 billion, primarily the result of the booking of Ch$ 35.2 billion related to the agreement reached with CELG Distribução S.A., the effect of an updating of the pension fund assets in Brazil and higher cash investments, primarily in Chilectra, Endesa Fortaleza and Enersis. There was also a positive effect from net exchange differences of Ch$ 8.7 billion, primarily arising from Brazil. This was partially offset by higher financial costs of Ch$ 27.1 billion, (which resulted primarily from updating our pension fund liabilities in Brazil and a higher average cost of debt), and greater indexation charges of Ch$ 10.0 billion, due to the effect of the UF value variation on UF-denominated debt for some of our Chilean companies. This value variation is due the value of the UF increasing 3.9% in 2011, compared to an increase of 2.5% in 2010.

Result of Asset Sales

The result of asset sales shows a decrease of Ch$ 17.6 billion, mainly due to the one-time booking of the loss on the sale of CAM during 2011.

As a result of the foregoing, total non-operating results increased by Ch$ 24.7 billion compared with the previous year.

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Net Income

The following table shows our net income for the year for the periods indicated.


	Year ended December 31,
	2011			2010			Change			% Change
	(in million of Ch$)
Operating income		1,566,311			1,704,301			(137,990	)		(8.1	)%
Non-operating results		(232,934	)		(257,606	)		24,672			9.6	%

Net income before taxes		1,333,377			1,446,695			(113,318	)		(7.8	)%

Income tax		(460,837	)		(346,007	)		(114,830	)		(33.2	)%

Net Income from Continuing Operations After Tax		872,540			1,100,688			(228,148	)		(20.7	)%
Net income from discontinued operations		0			0			0			0.0	%

Net Income		872,540			1,100,688			(228,148	)		(20.7	)%

Net Income attributable to: Shareholders of Enersis		375,471			486,227			(110,756	)		(22.8	)%

Net income attributable to: Non-controlling interests		497,069			614,461			(117,392	)		(19.1	)%

Corporate Income Tax

Income tax increased from Ch$ 346.0 billion in 2010 to Ch$ 460.8 billion in 2011, an increase of Ch$ 114.8 billion, or 33.2%. The impairment of prior tax credits in our Argentine subsidiaries, Edesur and Endesa Costanera, amounted to Ch$ 44.9 billion. Our Brazilian subsidiaries’ taxes increased by Ch$ 62.0 billion and are attributable to higher taxable income. Taxable income increased in precisely those countries where the corporate tax rate is higher, primarily in Brazil where the corporate tax rate virtually doubles the Chilean rate. The corporate tax rates in Brazil, Colombia, and Peru are 34%, 33% and 30%, respectively. In comparison, the Chilean corporate tax rate is much lower, although it increased, from 17% to 20%, starting on January 1, 2011. Such increase in income tax rate led to a higher income tax in Chile of Ch$ 8.5 billion.

The main changes in the corporate income tax expense of our subsidiaries were as follows: increases in Ampla of Ch$ 20.1 billion, CIEN of Ch$ 19.3 billion, Endesa Costanera of Ch$ 17.2 billion, Edesur of Ch$ 12.9 billion, Cachoeira Dourada of Ch$ 12.8 billion, Coelce of Ch$ 12.3 billion, Chilectra of Ch$ 10.2 billion, Endesa Chile of Ch$ 8.3 billion, San Isidro of Ch$ 7.3 billion, Edegel of Ch$ 6.8 billion, Codensa of Ch$ 5.8 billion, Enersis of Ch$ 5.6 billion and Emgesa of Ch$ 4.1 billion. These increases were partially offset by decreases in corporate income tax for Pehuenche of Ch$ 8.3 billion, Celta of Ch$ 4.0 billion and Gas Atacama of Ch$ 0.9 billion.

B.	Liquidity and Capital Resources.

We are a company with no significant assets other than the stock of our subsidiaries. The following discussion of cash sources and uses reflects the key drivers of our cash flow.

We receive cash inflows from our subsidiaries, as well as from related companies in Chile and abroad. Foreign subsidiaries and associates’ cash flows may not be available to satisfy our own liquidity needs, mainly because they are not wholly-owned, and because there is a time lag before we have effective access to those funds, through dividends or capital reductions.

However, we believe that cash flow generated from our business operations, as well as cash balances, borrowings from commercial banks, and ample access to both Chilean and foreign capital markets will be sufficient to satisfy all our needs for working capital, debt service, dividends and routine capital expenditures.

Set forth below is the consolidated cash flow from an accounting perspective:

127


	Year ended December 31,
	2012			2011			2010
	(in Ch$ billion)
Net Cash Flows from (used in) operating activities		1,561			1,698			1,943
Net Cash Flows from (used in) investing activities		(848	)		(624	)		(776	)
Net Cash Flows from (used in) financing activities		(1,012	)		(891	)		(1,283	)

Net increase (decrease) in cash and cash equivalents before effect of exchange rates changes		(300	)		183			(115	)
Effects of exchange rate changes on cash and cash equivalents		(63	)		76			(58	)
Cash and cash equivalents at beginning of period		1,220			961			1,135

Cash and cash equivalents at end of period		857			1,220			961

For the year ended December 31, 2012, cash provided by operating activities was Ch$ 1,561 billion, a decrease of 8.1% compared to 2011. This flow is mainly composed of cash receipts from sales and royalties of Ch$ 7,589 billion and other operating flows of Ch$ 392 billion, offset by payments to suppliers of Ch$ 3,935 billion, payment to employees of Ch$ 410 billion and other operating payments of Ch$ 2,076 billion.

For the year ended December 31, 2011, operating activities generated net cash flow of Ch$ 1,698 billion, a decrease of 12.6% when compared to 2010. This flow is mainly composed of cash receipts from collections from the sale of goods and services of Ch$ 7,726 billion and other operating flows of Ch$ 343 billion, partially offset by payments to suppliers for goods and services of Ch$ 3,942 billion and payments to and on behalf of employees of Ch$ 358 billion.

For the year ended December 31, 2012, cash used by investment activities was Ch$ 848 billion, a decrease of Ch$ 224 billion, or 35.9%, compared to 2011. These disbursements are mainly related to acquisition of Properties, Plant and Equipment of Ch$ 527 billion, the incorporation of intangible assets (IFRIC 12 in Brazil) of Ch$ 187 billion, and other investment disbursements of Ch$ 198 billion, partially compensated by interest received of Ch$ 57 billion and other investment amounts of Ch$ 8 billion.

For the year ended December 31, 2011, investment activities led to a cash outflow of Ch$ 624 billion, a 19.6% decrease compared to 2010. These disbursements relate mainly to the purchase of properties, plant and equipment of Ch$ 496 billion, the incorporation of intangible assets (IFRIC 12 in Brazil) of Ch$ 188 billion, and other investment disbursements of Ch$ 2 billion, partially offset by interest received of Ch$ 20 billion, cash flows from losing control of subsidiaries or other businesses of Ch$ 13 billion and other investment amounts of Ch$ 29 billion.

For the year ended on December 31, 2012, cash used by financing activities was Ch$ 1,012 billion. The main drivers of this cash flow are described below.

The aggregate cash inflows were mainly explained by:

•

Edegel obtained loans for Ch$ 4.8 billion.

•

Edelnor issued bonds for Ch$ 33 billion.

•

Emgesa obtained a total amount in loans and bonds of Ch$ 218 billion.

•

Ampla issued bonds for Ch$ 124 billion.

•

Coelce received funds from Banco do Nordeste do Brasil (BNB) for Ch$ 15 billion.

The aggregate cash outflows were mainly explained by:

•

Ch$ 547 billion in dividend payments (including Ch$ 186 billion from Enersis on a stand-alone, Ch$ 88 billion from Endesa Chile on a stand-alone basis among others).

•

Ch$ 254 billion of interest expense (including Ch$ 67 billion in Endesa Chile on a stand-alone basis, Ch$ 39 billion in Emgesa and Ch$ 67 billion in Endesa Brasil).

•

Endesa Brasil consolidated of Ch$ 272 billion of payments on loans, bonds and other instruments (including Ch$ 150 billion in Ampla, Ch$ 62 billion in Coelce and Ch$ 53 billion in CIEN).

•

Endesa Chile consolidated Ch$ 263 billion of payments on loans and other financial instruments.

128

For the year ended December 31, 2011, cash used by financing activities was Ch$ 891.4 billion. The main drivers are described below.

The aggregated cash inflows were mainly explained by:

•

Edegel obtained loans for Ch$ 15 billion.

•

Emgesa issued bonds for Ch$ 183 billion.

•

Endesa Brasil consolidated Ch$ 300 billion in loans and issued bonds for Ch$ 87 billion (including Ch$ 247 billion in Ampla and Ch$ 140 billion in Coelce) for a total of Ch$ 387 billion of cash inflow.

The aggregated cash outflows were mainly explained by:

•

Ch$ 648.1 billion in dividend payments (including Ch$ 253 billion from Enersis on a stand-alone basis and Ch$ 106 billion from Endesa Chile on a stand-alone basis, Ch$ 143 billion from Chilectra and Ch$ 79.4 billion from Codensa).

•

Ch$ 248.1 billion of interest expense (including Ch$ 109.7 billion in Endesa Chile on a consolidated basis and Ch$ 79.2 billion in Endesa Brasil).

•

Endesa Brasil consolidated Ch$ 315 billion of payments on loans (including Ch$ 53 billion in Endesa Brasil, Ch$ 106 billion in CIEN and Ch$ 150 billion in Ampla.

•

Endesa Chile consolidated Ch$ 55 billion of payments on loans and Ch$ 94 billion on other financial instruments (including Ch$ 81 billion on Emgesa’s bonds).

For a description of liquidity risks related to our company, please see “Item 3. Key Information — D. Risk Factors — We depend in part on payments from our subsidiaries and affiliates to meet our payment obligations” in this Report.”

We coordinate the overall financing strategy of our majority-owned subsidiaries. Our operating subsidiaries independently develop their capital expenditure plans. Generally, our policy is to have the operating subsidiaries independently finance their capital expansion programs through internally generated funds or direct financings. For information regarding our commitments for capital expenditures, see “Item 4. Information on the Company — A. History and Development of the Company — Investments, Capital Expenditures and Divestitures” and our contractual obligations table set forth below.

We have accessed the international equity capital markets, with an SEC-registered ADS issuances in October 1993, February 1996, September 2000 and February/March 2013 for us, and in 1994 for Endesa Chile. We have also issued bonds in the United States (“Yankee Bonds”) for each of Enersis and Endesa Chile. Since 1996, we, Endesa Chile and its subsidiary Pehuenche have issued a total of US$ 3,520 million in Yankee Bonds.

129

The following table lists the Yankee Bonds issued by us and Endesa Chile outstanding as of December 31, 2012. The weighted average annual interest rate for such bonds is 7.9%, without giving effect to each bond’s duration, or put options.


						Aggregate Principal Amount
Issuer	Term	Maturity	Coupon			Issued		Outstanding
			(as a percentage)			(in US$ million)

Enersis	10 years	January 2014		7.375	%		350		350
Enersis (1)	10 years	December 2016		7.400	%		350		250
Enersis (2)	30 years	December 2026		6.600	%		150		1

Subtotal				7.384	%		850		601

Endesa Chile	10 years	August 2013		8.350	%		400		400
Endesa Chile	12 years	August 2015		8.625	%		200		200
Endesa Chile (1)	30 years	February 2027		7.875	%		230		206
Endesa Chile (3)	40 years	February 2037		7.325	%		220		71
Endesa Chile (1)	100 years	February 2097		8.125	%		200		40

Subtotal				8.214	%		1,250		917


Total				7.886	%		2,100		1,518

(1)	Enersis and Endesa Chile repurchased bonds in 2001.

(2)	Holders of our 6.6% Yankee Bonds due 2026 exercised a put option on December 1, 2003 for an aggregate principal amount of US$ 149 million, leaving US$ 1 million outstanding.

(3)	Holders of the Endesa Chile 7.325% Yankee Bonds due 2037 exercised a put option on February 1, 2009 for a total amount of US$ 149.2 million. The remaining US$ 70.8 million principal amount of the Yankee Bonds mature in February 2037.

The following table lists Emgesa’s bond issued in the United States. The bond is denominated in Colombian pesos. The annual interest rate for such bond is 8.75%.

Coupon
(inflation-

Aggregate Principal Amount

Issuer

Term

Maturity

adjusted rate)

Issued

Outstanding

(as a percentage)

(Colombian
pesos billion)

(in US$ million)
(1)

Emgesa

10 years

January 2021

8.75

737

417

(1)	Calculated based on the observed exchange rate as of December 31, 2012, which was CPs$ 1,768.2 per US$ 1.00

We and Endesa Chile, as well as our subsidiaries in the five countries in which we operate, have access to the domestic capital markets where we have issued debt instruments including commercial paper and medium and long term bonds that are primarily sold to pension funds, life insurance companies and other institutional investors.

The following table lists UF-denominated Chilean bonds issued by us and Endesa Chile, outstanding as of December 31, 2012.


				Coupon (inflation-			Aggregate Principal Amount
Issuer (1) (2)	Term		Maturity	adjusted rate)			Issued		Outstanding
				(as a percentage)			(UF million)		(UF million)		(in US$ million)

Enersis Series B2		21 years	June 2022		5.75	%		2.5		1.5		64
Endesa Chile Series H		25 years	October 2028		6.20	%		4.0		3.4		161
Endesa Chile Series M		21 years	December 2029		4.75	%		10.0		10.0		476


Total					5.17	%		16.5		15		701

(1)	Endesa Chile Series F was pre-paid on February 1, 2012

(2)	Endesa Chile Series K was pre-paid on April 16, 2012

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For a full description of the local bonds issued by us and Endesa Chile, see “ — Unsecured liabilities detailed by currency and maturity” and “ — Secured liabilities breakdown by currency and maturity” in Note 18 to our Consolidated Financial Statements.

The following table lists local bonds issued by our foreign subsidiaries, outstanding as of December 31, 2012. We present aggregate information for each company. The maturity column for each company reflects the issuance with the longest maturity, and the coupon rate corresponds to the weighted average coupon of all issuances for each company.


Issuer	Maturity	Coupon (1) (as a percentage)			Aggregate Principal Amount Outstanding
					(in US$ million)

Ampla	June 2019		12.01	%		433
Codensa	December 2018		8.14	%		626
Coelce	October 2018		12.01	%		267
Edegel	January 2028		6.64	%		162
Edelnor	May 2032		6.89	%		314
Emgesa	December 2027		7.82	%		896


Total						2,698

(1)	Many of the coupon rates are variable rates based on local indexes, such as inflation. The table reflects the coupon rate taking into account each local index as of December 31, 2012.

We frequently participate in the international commercial bank markets governed by the laws of the State of New York through syndicated senior unsecured loans. As of December 31, 2012, the amounts outstanding or available for these bank loans are listed below:


Borrower	Type	Maturity	Facility Amount	Amount Drawn
			(US$ million)	(in US$ million)

Endesa Chile	Syndicated revolving loan	June 2014	200	0
Endesa Chile	Syndicated term loan	June 2014	200	200


Total			400	200

The Endesa Chile revolving credit facility due June 2014 do not contain a condition precedent requirement regarding the non-occurrence of a “Material Adverse Effect” (or MAE, as defined contractually) prior to a disbursement, allowing the Company full flexibility to draw on up to US$ 200 million in the aggregate from such committed revolving facilities under any circumstances, including situations involving a MAE.

We and Endesa Chile also borrow from banks in Chile under fully committed facilities in which a potential MAE would not be an impediment to this source of liquidity. In December 2009, both companies entered into 3-year bilateral revolving loans for an aggregate of UF 4.8 million (equivalent to US$ 228 million as of December 31, 2012). These loans expired on December 23, 2012 but, Endesa Chile’s loans were renewed for an aggregate amount of UF 2.4 million with a 3-year term starting in February 2013. We are in the process of renewing the loans mentioned above as of the date of this Report.

Our subsidiaries also have access to fully committed credit lines in the local markets, as detailed above.

Borrower

Type

Maturity

Facility Amount

Amount Drawn

(US$ million)

(in US$ million)

Ampla

Bilateral revolving loans

December 2014

110

Coelce

Bilateral revolving loans

June 2014

Emgesa

Bilateral revolving loans

January 2015

204

Total

363

As a result of the foregoing, we have access to fully committed undrawn revolving loans, both international and domestic, for up to approximately US$ 573 million in the aggregate as of December 31, 2012 (including two minor credit lines in Brazil). The above-mentioned committed credit lines of Endesa Chile executed during February 2013 add US$ 113 million, aggregating to a total amount of US$ 686 million.

131

We and Endesa Chile also borrow routinely from uncommitted Chilean bank facilities with approved lines of credit for approximately US$ 583 million in the aggregate, of which no amounts are currently outstanding. Unlike the committed lines described above not subject to MAE condition precedents prior to disbursements, this source of funding in the Chilean market is not guaranteed under all circumstances. Our subsidiaries also have access to uncommitted local bank facilities, for a total amount of US$ 1,027 million, of which US$ 1,023 million are undrawn as of the date of this Report.

Both we and Endesa Chile can also tap the Chilean commercial paper market under programs that have been registered with the Chilean SVS for a maximum of US$ 200 million for each borrower. In addition, we have a local bond program registered with the SVS for UF 12.5 million (equivalent to US$ 594 million as of December 31, 2012) that has not been drawn upon yet.

Finally, our foreign subsidiaries also have access to other types of financing, including governmental facilities, supplier credit and leasing, among others.

Except for the SEC-registered Yankee Bonds, which are not subject to financial covenants, we and Endesa Chile’s outstanding debt facilities include financial covenants. The types of financial covenants, and their respective limits, vary from one type of debt to another. As of December 31, 2012, the most restrictive financial covenant affecting us was the Debt Ratio, corresponding to the UF denominated Chilean bond Series B2 that matures in June 2022. For Endesa Chile, the most restrictive financial covenant was the Adjusted Consolidated Leverage Ratio in connection with the syndicated term and revolving facility that matures in June 2014. Under such covenant, the maximum additional debt that could be incurred without a breach of the most restrictive covenant is US$ 19.3 billion and US$ 5.7 billion for us and Endesa Chile, respectively. As of December 31, 2012 and as of the date of this Report, we are in compliance with the financial covenants contained in our debt instruments.

As is customary for certain credit and capital market debt facilities, a significant portion of our and Endesa Chile’s financial indebtedness is subject to cross default provisions. Each of the revolving credit facilities described above, as well as all of our and Endesa Chile’s Yankee Bonds, have cross default provisions with different definitions, criteria, materiality thresholds, and applicability as to the subsidiaries that could give rise to a cross default.

The cross default provision for the Endesa Chile revolving credit facilities due in July 2014, governed by the laws of the State of New York, refers to defaults of the borrower, without reference to any subsidiary. Under such credit facilities, only matured defaults exceeding US$ 50 million qualify for a potential cross default when the principal exceeds US$ 50 million, or its equivalent in other currencies. In the case of a matured default above the materiality threshold, the revolving credit facility’s lenders would have the option to accelerate if lenders representing more than 50% of the aggregate debt of a particular facility then outstanding choose to do so. None of the Endesa Chile local facilities due in February 2016, has cross default provisions to debt other than the respective borrower’s own indebtedness.

Cross default provisions of Enersis and Endesa Chile Yankee Bonds may be triggered only by the debt of the respective borrower or its Chilean subsidiaries. A matured default of either Enersis, Endesa Chile or one of their respective Chilean subsidiaries could result in a cross default to Enersis’ and Endesa Chile’s Yankee Bonds if such matured default, on an individual basis, has a principal exceeding US$ 30 million, or its equivalent in other currencies. In the case of a matured default above the materiality threshold, Yankee Bondholders would have the option to accelerate if either the trustee or bondholders representing no less than 25 % of the aggregate debt of a particular series then outstanding choose to do so. A payment default or a bankruptcy/insolvency default outside of Chile has no contractual effect on our Yankee Bond indentures, no matter how material. Likewise, neither our nor Endesa Chile’s local bonds have subsidiary cross default provisions.

132

the amount payable would be the full principal of US$ 141 million. Additionally, MC has a pledge as liens over the Mitsubishi combined cycle of Endesa Costanera. As of the date of this Report, we have not received any acceleration notice and negotiations to restructure the indebtedness are on-going. As of December 31, 2012, Endesa Costanera had a negative net worth and a deficit in its working capital, in both cases attributable to its inability to obtain tariff adjustments that truly reflect real generation costs. Defaults and cross defaults at the Endesa Costanera level do not trigger cross default provisions under indebtedness of Enersis or any of our Chilean subsidiaries. (See Notes 34.5 to our Consolidated Financial Statements and “Item 4. Information on the Company. –B. Business Overview. Electricity Industry Regulatory Framework –. Argentina. Regulatory Developments: the industry after the Public Emergency Law.”)

Payment of dividends and distributions by our subsidiaries and affiliates represent an important source of funds for us. The payment of dividends and distributions by certain subsidiaries and affiliates are subject to legal restrictions, such as legal reserve requirements, and capital and retained earnings criteria, and other contractual restrictions. We have been advised by legal counsel in the countries where our subsidiaries and affiliates operate that there currently are no additional legal restrictions on the payment to us of dividends or distributions to us in the jurisdictions where such subsidiaries or affiliates are incorporated. Certain credit facilities and investment agreements of our subsidiaries restrict the payment of dividends or distributions in certain special circumstances. For instance, one of Endesa Chile’s UF-denominated Chilean bonds restricts the amount of intercompany loans that Endesa Chile and its consolidated subsidiaries are allowed to lend to us. The threshold for such restriction of intercompany loans is the equivalent of US$ 100 million.

Our estimated capital expenditures for the 2013-2017 period, expressed in U.S. dollars at internally estimated exchange rates, amount to US$ 9,054 million, of which US$ 6,343 million are considered non-discretionary investments. We include maintenance capital expenditures as non-discretionary. It is important for us to maintain the quality and operation standards required for our facilities, but we do have some flexibility regarding the timing for these investments. We consider the investment in NCRE projects in Chile to be non-discretionary. These investments are being made to comply with regulations that call for 5% of the total contracted energy to be based on NCRE. Finally, expansion projects under execution are also non-discretionary. We consider the remaining US$ 2,712 million of the US$ 9,054 million of our estimated capital expenditure for 2013-2017 to be discretionary. The latter includes expansion projects that are still under evaluation, in which case we would undertake them only if deemed profitable.

Other than in Argentina, we do not currently anticipate liquidity shortfalls affecting our ability to satisfy the material obligations described in this Report. We expect to refinance our indebtedness as it becomes due, fund our purchase obligations outlined previously with internally generated cash, and fund capital expenditures with a mixture of internally generated cash and borrowings. We also expect to complete a capital increase by no later than April 2013, which if completed would result in at al least US$ 1.2 billion in cash proceeds.

Transactions that most significantly affected our foreign subsidiaries’ liquidity in 2012 included:

•

Coelce: funding from BNB for investment related projects for US$ 26 million.

•

Ampla: local bond issuance for US$ 200 million with five and seven year maturities, which enabled the company to increase the debt’s average life.

•

Emgesa: syndicated loan with local banks for US$ 173 million to refinance short-term debt and local bond issuance for US$ 283 million with 10- and 15-year maturity tranches.

•

Edelnor: local bond issuance for approximately US$ 68 million, used to refinance indebtedness.

•

Edegel: US$ 10 million in a five year term loan to refinance short term maturities in 2012.

Transactions that most significantly affected our foreign subsidiaries’ liquidity in 2011 included:

•

Endesa Costanera: refinancing of 2011 indebtedness for approximately US$ 80 million, including the US$ 35 million refinancing amounts due to Mitsubishi Corporation and of US$ 10 million due to Credit Suisse.

133

•

El Chocón: refinancing of a syndicated loan for US$ 40 million for four years. El Chocón also obtained a syndicated loan for US$ 24 million for 3.5 years, which enabled the company to increase the debt’s average life.

•

Edesur: refinancing of bank loans for a total of US$ 10 million for 2.5 years, which increased the debt’s average life; signed credit lines for US$ 6 million used to maintain an appropriate level of liquidity. Edesur received a total of US$ 40 million of bank loans.

•

Coelce: local bond issuance for US$ 221 million for five and seven year maturities, which allow the company to increase the debt’s average life. Coelce received loans for a total of US$ 34 million for development related projects.

•

Ampla: local bond issuance for US$ 195 million for five and seven year maturities, which allow the company to increase the debt’s average life. Also, Ampla received official loans for a total of US$ 102 million for development related projects and signed three committed credit lines for a total of US$ 75 million for liquidity purposes.

•

Emgesa: international bond issuance for a total of US$ 379 million for ten years, used to finance part of the El Quimbo project. Emgesa entered into exchange swap contracts for US$ 116 million.

•

Edelnor: refinancing of short-term debt for US$ 54 million, postponing it to 2018, thus allowing Edelnor to increase the debt’s average life.

•

Edegel: bank loan for US$ 31 million for seven years to refinance 2012 maturities in advance. Edegel also signed interest swap contracts for US$ 30 million to hedge leasing operations.

C.	Research and Development, Patents and Licenses, etc.

None.

D.	Trend Information.

Our subsidiaries are engaged in the generation, transmission and distribution of electricity in Chile, Brazil, Colombia Peru and Argentina. Therefore, our businesses are subject to a wide range of conditions that may result in variability in our earnings and cash flows from year to year. In general, our net income is a result of our operating income from our generation and distribution businesses and other factors such as income from unconsolidated related companies, foreign currency exchange rate effects and tax expense.

In our generation business, our operating income for the year ended December 31, 2012 decreased by 19.4 % as compared to 2011. This percent change in the generation segment operating income in 2012 varies in each of the five countries where we operate and is due to numerous factors, including hydrological conditions, the price of fuel used to generate thermal electricity and the prevailing spot market and regulated prices for electricity. We expect to continue evidencing a reasonably good operating performance over the coming years, given the favorable macroeconomic perspective for all of the countries in which we operate except for Argentina. Despite current uncertainties concerning the global economy, there are good expectations for this region’s growth for the next five years, including an expected 4.6 % growth in gross domestic product, on average, based on World Economic Outlook (October 2012) of the International Monetary Fund (IMF) and a stable electricity demand growth.

On the other hand, development of new generation facilities in South America has always fallen behind demand growth. We anticipate that this tendency will continue in the foreseeable future. Also, due to growing environmental restrictions, transmission line saturation, obstacles for fuel transportation and scarcity of places where to locate plants, these new projects involve higher development costs than in the past. We expect that average electricity prices will adjust to recognize these increased costs. This could increase the value of our assets, especially in the case of hydroelectric power plants, which have lower production costs, and thus benefit from greater profitability in scenarios of increasing prices to end users. Furthermore, an important part of the new installed capacity under development in the five countries in which we operate corresponds to thermal power plants, with coal and natural gas as their principal fuels, and only a few hydroelectric projects are being developed. Thus, we expect this situation will also impact long term spot prices positively. Long term contracts awarded to Enersis’ subsidiaries in different bids have already incorporated these expected price levels. Currently, 25% of our expected annual generation is sold under contracts of at least ten years and an additional 34% under contracts of at least five years.

However, spot prices are subject to great volatility, affecting our forecasted income. In order to address this risk in the generation business, we have implemented commercial policies in order to control relevant variables and provide stability to the profit margins. Our commercial policy seeks to establish a global framework to conduct energy trading operations, setting responsibilities,

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guidelines and acceptable risk limits aligned with company objectives. Therefore, the company defines contractual volumes that minimize the risk of supply in adverse hydrological conditions and includes, where necessary with some unregulated clients, risk mitigation clauses.

In order to mitigate the risk of increasing fuel costs, certain of our subsidiaries have entered into supply contracts to cover part of the fuel needed to operate the thermal generation units, which operate with coal, natural gas, diesel and fuel oil. In Chile, through an equity interest in GNL Quintero, we are the only electricity company that participates in the LNG terminal at Quintero Bay (the only facility of its kind in the SIC market), enhancing our position to manage fuel supply risks, especially when facing increasing fuel costs scenarios. This becomes particularly relevant given the increasing trend to penalize other technologies that are intensive in fuels, such as coal and diesel, which have a stronger environmental impact. Endesa Chile, through a subsidiary, entered into the Flexible Liquefied Natural Gas Sale and Purchase Agreement with a subsidiary of British Gas (“BG”) on May 31, 2007 (2.2 million m³ per day until 2030), pursuant to which Endesa Chile changed its supply arrangements effective January 1, 2013 resulting in a significant reduction in price because the reference price changed from the Brent index to the Henry Hub index. BG has proposed a material increase in the price post-January 1, 2013, but the contract does not provide for contractual renegotiation under these circumstances. To force a negotiation, BG notified Endesa Chile that some shipments (up to 50% of the contract quantity) in 2013 would not be delivered. If BG fails to deliver LNG, Endesa Chile must commence arbitration proceedings under the contract to try to recover the additional costs incurred in replacing the undelivered LNG shipments by BG. For Endesa Chile, the estimated cost of non-delivery of a LNG shipment from BG is US$ 46 million at spot price. Most of Endesa Chile’s LNG consumption is covered by the BG contract. In addition, because of the drought in Chile and price volatility of coal and petroleum, Endesa Chile decided to hedge this risk with commodity instruments available in international markets. As of December 31, 2012, there are swap arrangements outstanding of 462 thousand barrels of Brent crude for January 2013 and 365 thousand tons of coal for the period from February 2013 through June 2013. Endesa Chile plans to continuously monitor operating conditions and, if necessary, modify or supplement these swap arrangements. For further information on this subject, please see “Item 3. Key Information — D. Risk Factors — If British Gas fails to make any of the natural gas deliveries it is obligated to make to us, we may incur replacement costs that we may not be able to recoup.” and “Item 11(a) and 11(b). Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”

With respect to our distribution business segment, our operating income for the year ended December 31, 2012, increased by 18.0% as compared to 2011. This increase is a combination of numerous factors in each of the five countries where we operate. These include, among others, operational efficiency and the increase in electricity sales due to growth in population and gross domestic product in the countries in which we operate and the non-recurrence of an exceptional tax payments that affected operating income in 2011. These increases were partially offset by higher operational cost and effects of conversion to Chilean pesos. Technological advances, such as smart metering, have enabled us to limit the increase in electricity losses in a challenging economic environment. We expect that the South American countries in which we operate will continue to experience high growth rates, positively impacting our distribution business performance. In particular, we expect the growth rates in the electricity sector to continue, mainly due to the gap in the per capita electricity consumption that these countries have with respect to more developed countries. We estimate that electricity demand will grow approximately 4% annually, on average, over the next ten years.

In connection with the distribution segment tariffs, and taking into account the future periodic review process in each country in which we operate, we expect that the regulators will continue to recognize investments, encourage efficiency and establish prices that will allow for an appropriate return on our investment. We also anticipate that our distribution companies will probably increase their profitability during the period between periodic tariff setting processes, according to price cap tariff model, for growth and economies of scale. After tariffs have been set, the companies have the opportunity to increase their efficiency, and obtain extra profits associated with such efficiencies, during the period subsequent to each new tariff setting. For a better understanding of the cycles in the process, please refer to the figure below, where we conceptually describe the effect of the application of the price cap model used by regulators in most of the countries where we operate.

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LOGO

Although the price at which a distribution company purchases the electricity has a substantial impact on the price at which it is sold to end users, it does not have an impact on our profitability. The cost of electricity purchased is passed through to end users. However, distribution companies usually enter into long-term contracts in order to decrease exposure to electricity price volatility. This is a common practice in most of the countries in which we operate generation companies.

Though our operations in the five countries allow us to somewhat offset and counterbalance variations with respect to these main factors that affect our operating results, in light of the variability of these factors over time and across the countries in which we operate, we cannot claim that we are fully hedged in our portfolio of assets in these countries. Furthermore, we cannot ascertain the likelihood or the extent to which past performance will be indicative of future performance with respect to our businesses. Any significant change with respect to hydrological conditions, fuel price or the electricity price, among other factors, could affect our operating income in the generation business. More broadly, any significant change with respect to economic and population growth, as well as changes in the regulatory regimes in the countries in which we operate, among other factors, could affect our operating income in the distribution business. Variability in our earnings and cash flows can also arise from non-operating factors as well, such as foreign currency exchange rates. For further information regarding our 2012 results compared with those recorded in previous periods, please see “— A. Operating Results — 2. Results of Operations for the Years ended December 31, 2012 and December 31, 2011” and “— A. Operating Results — 3. Results of Operations for the Years ended December 31, 2011 and December 31, 2010”. Investors should not look at our past performance as indicative of future performance.

We do not expect that our current debt agreements, which impose certain restrictions, could have a negative impact on our capital expenditure plan as described above in “— B. Liquidity and Capital Resources”. As of December 31, 2012, Enersis is able to incur up to US$ 16.4 billion in incremental debt, while Endesa Chile has an additional debt capacity of US$ 5.7 billion, without entering into breach of the debt financial covenants, in each case beyond current levels of consolidated indebtedness. We believe that Enersis will continue to have similar comfortable levels of further leverage capacity in the foreseeable future.

In connection with funding sources, as of December 31, 2012, we had approximately US$ 573 million in committed revolving facilities which have not yet been drawn, uncommitted Chilean lines of credit for another US$ 583 million in the aggregate and additional undrawn uncommitted bank facilities of our foreign subsidiaries of US$ 1,023 million. In addition, both we and Endesa Chile, on an individual basis, have publicly registered certain commercial paper programs for up to US$ 400 million in the aggregate and local bond programs for up to US$ 594 million with the SVS. These funding sources can be increased in case of need. We also expected to complete a capital increase by no later than April, 2013, which, if completed, would result in at least US$ 1.2 billion in cash proceeds.

Finally, as explained above, we expect that we will continue generating substantial operating cash, which can be used to finance a significant part of our capital expenditure plan. If needed, our shareholders can also decrease the dividend payout ratio, subject to certain minimum legal restrictions, in order to finance our investment plan and future growth.

E.	Off-balance Sheet Arrangements.

Enersis is not a party to any off-balance sheet arrangements.

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F.	Tabular Disclosure of Contractual Obligations.

The table below sets forth the Company’s cash payment obligations as of December 31, 2012:


Ch$ billion (1)	Total		2013		2014-2015		2016-2017		After 2017
Bank debt		401		106		153		63		79
Local bonds (2)		1,593		146		292		397		758
Yankee bonds		1,147		192		386		216		353
Other debt (3)		275		129		75		41		30
Interest expense		1,505		272		382		267		584
Pension and post-retirement obligations(4)		283		48		80		71		84
Purchase obligations(5)		27,574		1,591		3,851		3,149		18,983
Financial leases		66		12		18		22		14

Total contractual obligations		32,844		2,496		5,237		4,226		20,885

(1)	All figures are in billion Ch$ of each year.

(2)	Hedging instruments included modify substantially the principal amount of debt.

(3)	Other debt includes governmental loan facilities, supplier credits and short—term commercial paper among others.

(4)

We have funded and unfunded pension and post-retirement benefit plans. Our funded plans have contractual annual commitments for contributions which do not change based on funding status. Cash flow estimates in the table are based on such annual contractual commitments including certain estimable variable factors such as interest. Cash flow estimates in the table relating to our unfunded plans are based on future discounted payments necessary to meet all of our pension and post-retirement obligations.

(5)

Includes generation and distribution business purchase obligations comprised mainly of energy purchases, operating and maintenance contracts and other services. Of the total amount of Ch$ 27,574 billion, 88% corresponds to energy purchases, 6% corresponds primarily to fuel supply, services in medium and low voltage lines, and supply of cables, and the remaining 6% to miscellaneous services, such as LNG regasification, fuel transport and coal handling.

G.	Safe Harbor.

The information contained in the Items 5.E and 5.F contains statements that may constitute forward-looking statements. See “Forward-Looking Statements” in the “Introduction” of this Report, for safe harbor provisions.

Item 6.

Directors, Senior Management and Employees

A.	Directors and Senior Management.

Our Board of Directors consists of seven members who are elected for a three-year term at an Ordinary Shareholders’ Meeting (OSM). If a vacancy occurs in the interim, the Board of Directors elects a temporary director to fill the vacancy until the next OSM, at which time the entire Board of Directors will be elected. Our Executive Officers are appointed by the Board of Directors and hold office at the discretion of the Board.

Set forth below are the members of our Board of Directors as of December 31, 2012.


Directors	Position	Held Since
Pablo Yrarrázaval V.	Chairman	2002
Andrea Brentan	Vice Chairman	2009
Rafael Fernández M.	Director	2010
Rafael Miranda R.	Director	1999
Hernán Somerville S.	Director	1999
Eugenio Tironi B.	Director	2000
Leonidas Vial E.	Director	2010

Set forth below are brief biographical descriptions of our directors, five of whom reside in Chile and two in Spain, as of December 31, 2012.

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Pablo Yrarrázaval V.

Chairman of the Board of Directors

Mr. Yrarrázaval became Chairman of the Board of Directors in July 2002 and was Chairman of the Directors’ Committee since April 2003 until January 2010. Mr. Yrarrázaval is a partner in the brokerage firm Corredora de Bolsa Yrarrázaval y Compañía Limitada, and is also Chairman of the Santiago Stock Exchange, a position he has held since 1989. Before Mr. Yrarrázaval became Chairman of Enersis, he was Chairman of Endesa Chile.

Andrea Brentan

Vice Chairman of the Board of Directors

Mr. Brentan has been Vice Chairman since 2009. Mr. Brentan has also been the CEO of Endesa Spain since July 2009. He was a research assistant at New York University from 1975 to 1977 and then held various positions at GIE, an Italian power plant contractor operating worldwide, until the beginning of 1991. From 1991 to 1999, he successively held the positions of CFO, General Manager and CEO at Sae Sadelmi, a Milan-based company belonging to the ABB Group which is engaged in power plant engineering, procurement and construction and electrical generation equipment manufacturing and service. From 2000 to 2002, he was the Head of the Worldwide Steam Power Plant Business at Alstom, based in Paris. He joined Enel in November 2002, where he held several positions in the company, including Head of Business Development and M&A unit of the International Division, Chairman of Viesgo S.A., Chairman of Enel North America, Enel Latin America and Slovenske Elektrarne, and Director of Enel Energy Europe. Until June 2009, he served as Director of the Iberian Peninsula and Latin American Division of Enel and Vice Chairman of the Board of Endesa Spain. Mr. Brentan is a mechanical engineer from Politecnico di Milano (Italy) and holds a M.Sc. in Applied Sciences from New York University.

Rafael Fernández M.

Director of the Board, Member of the Directors’ Committee

Mr. Fernández was appointed Director of Enersis in April 2010. From 1997 to 2006, Mr. Fernández served as Chairman of the Board and Director of various Argentine companies in the generation, transmission, distribution and trading businesses of electricity, as well as in natural gas production and transport companies. Before that, he was CEO of some power generation companies. He also founded and was a member until 2004 of the Academic Committee in the Masters Program in Electricity Business at ITBA (Argentina) and, between 2006 and 2012, was a member of the Advisory Committee of the Development Department of Universidad Alberto Hurtado (Chile). Between 2002 and 2006, he was the Executive Director of the Gas and Energy Business division and member of the Board of Directors of Petrobras Energía—Argentina. Between 2006 and January 2010, he served as CEO and Director of Petrobras Chile Petrolera Ltda. Since October 2011, he has been Director of the Board of Australis Seafood S.A., and since June 2010, has been CEO of Corporación de Capacitación y Empleo, a subsidiary of Sociedad de Fomento Fabril (SOFOFA). Mr. Fernández is a civil industrial engineer from Pontificia Universidad Católica de Chile. He also carried out graduate studies at E.S.A.E. in the same university in 1988-1989, and an Advanced Management Program at Duke University in 2005.

Rafael Miranda R.

Director of the Board

Mr. Miranda has been a Director of the Board since 1999. He joined Endesa Spain in 1987. From 1987 to 1997, he was Managing Director. Between February 1997 and June 2009, he served as Endesa Spain’s CEO. Currently, Mr. Miranda is Chairman of Endesa Foundation, Honorary Chairman of Eurelectric (European Electricity Association), Chairman of the Social Council of Burgos University, Chairman of the Spanish Council of INSEAD (all in Spain), and Chairman of Asociación para el Progreso de la Dirección, an entity formed by the 4,000 largest Spanish companies dedicated to cooperate with directors and senior executives’ development. Mr. Miranda holds a B.Sc. in Industrial Engineering from Comillas University (ICAI) and a Master’s Degree in Management Science from the School for Industrial Organization, both in Spain.

Hernán Somerville S.

Director of the Board, Chairman of the Directors’ Committee

Mr. Somerville has been a Director of the Board since 1999. From 1983 to 1988, Mr. Somerville was Director of the Central Bank of Chile, serving as Chief Debt Negotiator for Chilean public debt and private commercial bank debt. Mr. Somerville was the former Chairman of the Confederation of Production & Commerce in Chile. Since 1989, Mr. Somerville has been the Managing Director and Partner of Fintec, an investment, advisory and management company. He was the Chairman of the Chilean Association of Banks and Financial Institutions, and also was Chairman of the Latin American Federation of Banks. He is the Chairman of Transbank S.A., which manages credit and debit cards in Chile. He is also a Board Member of INACAP and Chairman of the Chilean Pacific Foundation. Mr. Somerville has a law degree from Universidad de Chile and studies in Comparative Law at New York University Law School.

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Eugenio Tironi B.

Director of the Board

Mr. Tironi has been a Director of Enersis since July 2000. Between 1990 and 1994, Mr. Tironi was a Director of Communications of the Chilean Government. Since 1994, he has been the Chairman of Tironi Asociados, a strategic communications’ firm, which advises Chilean and international firms in several Latin American countries. He is also the Chairman of Gestión Social S.A., a consulting firm specialized in corporate social responsibility. In addition, Mr. Tironi is member of the Board of Trustees of Universidad Alberto Hurtado, researcher at CIEPLAN, and professor at Universidad Adolfo Ibáñez. He was a visiting professor at Notre Dame University (U.S.A.) in 2002, and Sorbonne Nouvelle (France) in 2006. He is also a Board member of several non-profit organizations, including Paz Ciudadana, Un techo para Chile and Fundación Orquestas Sinfónicas Juveniles e Infantiles. Mr. Tironi has published a very wide selection of books in Chile and abroad, and is a regular columnist of the Chilean newspaper, El Mercurio. Mr. Tironi received a Ph.D. in sociology from L’École des Hautes Études en Sciences Sociales (France).

Leonidas Vial E.

Director of the Board, Member of the Directors’ Committee

Mr. Vial was appointed Director of Enersis in April 2010. He was Director of Endesa Chile from April 1995 until March 2010. Mr. Vial has been Vice Chairman of the Santiago Stock Exchange since June 1988, as well as a Director of Empresas Santa Carolina S.A., Compañía Industrial El Volcán S.A., Larraín Vial S.A., Chairman of Compañías CIC S.A. and Embotelladora Arica, none of which are related to the Endesa Group.

Executive Officers

Set forth below are our Executive Officers as of December 31, 2012.


Executive Officers	Position	Current Position Held Since
Ignacio Antoñanzas A.	Chief Executive Officer	2006
Massimo Tambosco	Deputy Chief Executive Officer	2010
Ramiro Alfonsín B.	Planning and Control Officer	2007
Ángel Chocarro G.	Accounting Officer	2009
Eduardo Escaffi J.	Chief Financial Officer	2012
Juan Pablo Larraín M.	Communications Officer	2009
Eduardo López M.	Procurement Officer	2010
Carlos Alberto Niño F.	Human Resources Officer	2010
Alain Rosolino	Internal Audit Officer	2012
Francisco Silva B.	General Services Officer	2010
Domingo Valdés P.	General Counsel	1999

Set forth below are brief biographical descriptions of our Executive Officers, all of whom reside in Chile:

Ignacio Antoñanzas A. was appointed CEO of Enersis in October 2006. He started his career as a commodities trader. He joined Endesa Spain in 1994, having worked during his professional career mostly in generation and corporate strategy areas. He was the CEO of Endesa Net Factory and Director of Endesa Italia. Until assuming his current position, he served as Deputy General Manager of Strategy for Endesa Spain. Since June 2009, he also serves as Executive Vice President at Endesa Spain in charge of Latin America. Mr. Antoñanzas holds a degree in mining engineering with a major in energy and fuels from the Universidad Politécnica de Madrid, Spain.

Massimo Tambosco became Deputy Chief Executive Officer in October 2010. Between 2000 and 2009, he held several positions in finance, planning and control, corporate control and M&A for different Enel Group companies and business units. Previously, he was CFO of Ferrero de México and Administration Manager of Roca S.r.l in Italy. From March 2009 until his most recent appointment, he held the position of Deputy CFO of Endesa Spain. Mr. Tambosco holds a degree in business administration from the Università Commerciale Luigi Bocconi di Milano (Italy), and attended Executive Programs in the Kellogg School of Management in Chicago and the Harvard Business School in Boston.

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Ramiro Alfonsín B. became Planning and Control Officer in March 2007. He joined the Endesa Group in June 2000, working in Spain for Endesa Net Factory as Investment and Risk Capital Manager and later as Planning and Control Manager. Subsequently, he worked in Endesa Italia in Rome as Planning and Investment Deputy Director and in Endesa Europa as Investment and Corporate Relations Deputy Director. Currently, Mr. Alfonsín is board member of several of Enersis’ companies in Argentina, Brazil, Chile and Colombia. Before joining the Endesa Group, Mr. Alfonsín worked as Senior Financial Advisor at Banco Urquijo KBL Group, as Management Advisor of the Corporate Development and Institutional Relations at Alcatel, and also as Corporate Banking Associate at ABN Amro Bank N.V. He holds a degree in Business Administration from the Pontificia Universidad Católica de Argentina.

Ángel Chocarro G. has been Enersis’ Accounting Officer since November 2009. Mr. Chocarro has held several positions in both Enersis and the Endesa Spain Group. He served as CFO and Chief Controlling Officer of the Chilean telecommunications company, Smartcom, from 2002 to 2005. From 2005 to 2009, he was Enersis’ Director of Consolidation, Internal Controls, and Accounting Criteria. Mr. Chocarro has a degree in Economics and Business Administration from Universidad del País Vasco (Spain) and has an M.B.A. degree from Instituto de Empresa (Spain).

Eduardo Escaffi J. became the CFO of Enersis in August 2012, after serving as CFO of Endesa Chile for three years from October 2009. From 1999 to 2009, Mr. Escaffi served in the Finance and Risk departments of Endesa Spain. He was previously the CFO of Enersis from July 1998 to August 1999. Prior to that, Mr. Escaffi was the CEO of an Argentine insurance company from 1992 to 1998. He also held the position of Technical and Financial Manager of the life insurance company of the Santander Group in Chile from 1989 to 1992. In 1989, he served as the Deputy Financial Officer of Compañía de Teléfonos de Chile. Between 1986 and 1988, he served as adviser to the United Nations Development Program in Venezuela. Mr. Escaffi has also held several positions in Chilean governmental entities such as ODEPLAN and the Ministry of the Interior. Mr. Escaffi is a civil engineer from the Universidad de Chile, with a specialization in structural engineering, and a Senior Executive Programme degree from the London Business School.

Juan Pablo Larraín M. joined Enersis in August 2006 as Chilectra’s Communications Officer. In October 2009, he was appointed Enersis’ Communication Officer and Endesa Spain’s Communication Officer for Latin America and Chile. Before joining Enersis, he worked as Editor in Chief of Diario Financiero, Communications’ Officer at Hill & Knowlton Chile, National Editor at El Mercurio (Valparaíso) and News Service Editor at Red TV. Mr. Larraín graduated from the School of Journalism at Finis Terrae University (Chile) and holds a Master’s Degree in Professional Journalism from Complutense University (Spain).

Eduardo López M. was appointed Enersis’ Procurement Officer in June 2008. He joined the group in 1981, having held several positions in the financial department in Chilectra until 1992. Between 1992 and 1995, he worked at Edesur where he served as Sales Director. He was also CEO at Diprel S.A., a former Enersis subsidiary, between 1996 and 2001. In 2002, he was appointed as Enersis’ Procurement Director and from 2004 until 2008 he held the same position at CAM. Mr. López is a commercial engineer from Pontificia Universidad Católica de Valparaíso (Chile).

Carlos Niño F. was appointed Enersis’ Human Resources Officer in December 2010. He joined the group in 1998, having held several positions as Human Resources Officer at different companies, including Codensa and Emgesa in Colombia and Chilectra in Chile. He was also appointed Endesa Latinoamérica Personnel Management Director in 2009. Previously, he was Personnel Director of Legis S.A. and Human Resources Officer of Colmena Salud, a health insurance company. Mr. Niño is a lawyer from Universidad Externado de Colombia and holds a M.Sc. in Labor and Social Security Law from the Pontificia Universidad Javeriana (Colombia).

Alain Rosolino was appointed Internal Audit Officer in December 2012. He joined the Enel Group in 2003, having held several positions in the audit area at Enel, Enel Rumania, Enel Green Power in Latin America, and from 2011 to 2012, at Enel EGP IBAL (Iberian Peninsula and Latin America). Mr. Rosolino holds a business administration degree from LUISS University (Italy).

Francisco Silva B. was appointed Enersis’ General Services Officer of Enersis in December 2010. Mr. Silva joined Chilectra in 1987 and has worked primarily in human resources and general management positions in several subsidiaries and affiliates of Enersis since then. Between 1998 and 2000 and between July 2003 and December 2010 he was Enersis’ Human Resources Officer. From January 2001 to June 2003, he worked as Adjunct Director of an Endesa Spain subsidiary in Spain. Mr. Silva holds a degree in public administration from Universidad de Chile, and received a DPA diploma from Universidad Adolfo Ibáñez (Chile), in 1986.

Domingo Valdés P. has been General Counsel since May 1999. He joined the Enersis Group as a corporate attorney at law for Chilectra in 1993 and became Legal Counsel at Enersis in December 1997. Mr. Valdés worked as an intern at the New York City law firms of Milbank, Tweed, Hadley & McCloy and Chadbourne & Parke LLP. Before joining Chilectra, Mr. Valdés was a lawyer at Chase Manhattan Bank, N.A., Corporate Department (Chile) and an associate at Carey & Cía., a Santiago based law firm. Mr. Valdés is also Secretary of the Enersis Board of Directors and a Professor of Economic and Antitrust Law at Universidad de Chile Law School. Mr. Valdés has a law degree from Universidad de Chile and a Master of Law Degree from the University of Chicago.

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B.	Compensation.

At the ordinary shareholders’ meeting held on April 26, 2012, our shareholders approved the current compensation policy for the Board of Directors. Directors are paid a variable annual fee, depending on net earnings of the Company, in a relation one per one thousand, and a monthly fee paid in advance, depending on their attendance to the board meetings and their participation as Director of any of our subsidiaries. These advances consist of a fixed compensation of UF 101 per month and a fee of UF 66 for attending meetings of the Board. The Chairman of the Board (in this case Mr. Yrarrázaval) is entitled to double the compensation for a regular Director under this policy. In 2012, the total compensation paid to each of our directors, including fees for attendance at meetings of the Directors’ Committee, was as follows:


Director	Variable Compensation		Fixed Compensation		Directors Committee		Total
	Year ended December 31, 2012 (in thousands of Ch$)
Pablo Yrarrázaval V.		65,816		54,839		—		120,654
Andrea Brentan (1)		—		—		—		—
Rafael Fernández M.		33,722		27,419		—		61,141
Rafael Miranda R.		32,908		27,419		18,479		78,806
Hernán Somerville S.		33,722		27,419		—		61,141
Eugenio Tironi B.		32,908		27,419		18,886		79,213
Leonidas Vial E.		33,314		27,419		18,886		79,620

Total		232,389		191,935		56,251		480,575

(1)	Mr. Brentan waived his compensation as Board Director.

We do not disclose, to our shareholders or otherwise, information on individual Executive Officer’s compensations. For the year ended December 31, 2012, the aggregate gross compensation paid or accrued, attributable to fiscal year 2012, including performance—based bonuses for the Executive Officers of Enersis, was Ch$ 2,616 million. Enersis’ Executive Officers are eligible for variable compensation under a bonus plan for meeting company—wide objectives and for their individual contribution to the Company’s results and objectives. The annual bonus plan provides for a range of bonus amounts according to seniority level. The bonuses paid to executives consist of a certain number of gross monthly salaries.

The amount accrued by the Company in 2012 to provide for pensions, retirement or similar benefits to our Executive Officers totaled Ch$ 250 million. The funds accrued to provide severance indemnity to our Executive Officers amounted to Ch$ 460 million, of which Ch$ 96 million was accrued during 2012. There are no other amounts set aside or accrued to provide for pension, retirement or similar benefits for our Executive Officers.

All of our Executive Officers have severance indemnity agreements with the Company in the event of voluntary resignation, mutual agreement among the parties, or death. They do not have a right to severance indemnity if their relationship with the Company is terminated due to willful misconduct, prohibited negotiations, unjustified absences, abandonment of duties, among other causes, as defined in article 160 of the Chilean Code of Labor. All of the Company’s employees are entitled to legal severance pay if dismissed due to the needs of the Company, as defined in article 161 of the Chilean Labor Code.

C.	Board Practices.

The Board of Directors as of December 31, 2012 was elected at the OSM of April 22, 2010, and the term for this Board of Directors will expire in April 2013. For information as to the years in which each director began his service on the board, please see “— A. Directors and Senior Management” above. The members of the Board of Directors do not have service contracts with Enersis or any of its subsidiaries that provide benefits upon termination of employment.

Corporate Governance

Enersis is managed by its Board of Directors, which, in accordance with its bylaws, consists of seven directors who are elected at an OSM. Each director serves for a three-year term and the term of each of the seven directors expires on the same day. The directors can be reelected indefinitely. Staggered terms are not permitted under Chilean law. If a vacancy occurs on the board during the three—year term, the Board of Directors may appoint a temporary director to fill the vacancy. Any vacancy triggers an election for every seat on the Board of Directors at the next OSM.

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Chilean corporate law provides that a company’s board of directors is responsible for the management, administration and representation of a company in all matters concerning its corporate purpose, subject to the provisions of the company’s bylaws and the stockholders’ resolutions. In addition to the bylaws, the Enersis Board of Directors has adopted regulations and policies that guide our corporate governance principles.

The Charter Governing Executives, approved by our Board on May 28, 2003, and the Employee Code of Conduct, explain our principles and ethical values, establish the rules governing our contact with customers and suppliers, and establish the principles that should be followed by employees, including ethical conduct, professionalism and confidentiality. They also impose limitations on the activities that our executives and other employees may undertake outside the scope of their employment with us.

In order to ensure compliance with Securities Market Law 18,045 and SVS regulations, our Board of Directors at its meeting held on May 28, 2008, approved the “Manual for the Management of Information of Interest to the Market” (“Manual”). This document addresses applicable standards regarding the information in connection with transactions of the Company’s securities or those of its affiliates by directors, management, principal executives, employees and other related parties, existence of blackout periods for such transactions by directors, principal executives and other related parties, existence of mechanisms for the continuous disclosure of information that is of interest to the market and mechanisms that provide protection for confidential information. The Manual was released to the market on May 30, 2008 and posted on the Company’s website at www.enersis.cl. In February 2010, the Manual was modified in order to comply with the provisions of Law 20,382 (Corporate Governance Improvement Law).

The provisions of this Manual shall be applied to the members of our Board, as well as Enersis executives and employees who have access to privileged information, and especially those who work in areas related to the securities markets.

In order to supplement the aforementioned corporate governance regulations, the Company’s Board, at its meeting held on June 24, 2010 approved a Code of Ethics and a Zero Tolerance Anti-Corruption Plan (“ZTAC Plan”). The Code of Ethics is structured on the basis of general principles such as impartiality, honesty, integrity and other values of similar importance, which are expected in the behavior criteria detailed in the document. The ZTAC Plan reinforces the principles included in the Code of Ethics, but with special emphasis on avoiding corruption in the form of bribes, preferential treatment and other similar matters.

At its meeting of March 29, 2011 Enersis’ Board approved the Prevention Model required by Law 20,393 of December 2, 2009, which imposes criminal responsibility on legal entities for the crimes of asset laundering, financing of terrorism and bribing of public officials. The law encourages companies to adopt this model, whose implementation involves compliance with duties of management and supervision. The adoption of this model therefore mitigates, and in some cases relieves, the effects of criminal responsibility even when a crime is committed. One of the elements of this model is the Prevention Officer which was appointed by the Board at its meeting held on October 27, 2010. As of December 31, 2012, our Prevention Officer was Alain Rosolino, Internal Audit Officer.

On October 27, 2010, the Board approved “GUIDELINES 231: Guidelines applicable to non-Italian subsidiaries in accordance with Legislative Decree 231 of June 8, 2001. Application to Endesa Spain and its Group.” Given that Enersis’ ultimate parent company, Enel S.p.A. has to comply with Legislative Decree 231, which establishes management responsibility for Italian companies as a consequence of certain crimes committed in Italy or abroad, in the name of or for the benefit of such entities, including those crimes described in Chilean Law 20,393, this document, approved by the Board, sets a group of measures, with standards of behavior expected from all employees, advisers, auditors, officials, directors as well as consultants, contractors, commercial partners, agents and suppliers. Decree 231 includes various activities of a preventive nature that are coherent with and integral to the requirements and compliance with Chilean Law 20,393, which deals with the criminal responsibility of legal entities. All of the above is supplementary to the behavioral regulations included in the Code of Ethics and ZTAC Plan.

On November 29, 2012, the SVS issued General Regulation No. 341 which establishes regulations for the disclosure of information with respect to the standards of corporate governance adopted by publicly held limited liability corporations that must be complied with, and sets the procedures, mechanisms and policies that are indicated in the Appendix to the regulation. The objective of this regulation is to provide suitable information to the investing public with respect to good corporate governance policies and practices adopted by publicly held limited liability corporations, which include Enersis, and permit entities like stock exchanges or research centers to produce their own analyses to help the various market players know and evaluate the commitment of companies. The Appendix is divided into the following five sections with respect to which companies must report the corporate practices that have been adopted: (i) the functioning of the board, (ii) relations between the company, shareholders and the public in general, (iii) the replacement and compensation of senior executives, (iv) the definition, implementation and supervision of the company’s internal control and risk management policies and procedures, and (v) other practices adopted by the company that do not refer to the above matters. Publicly held limited liability corporations should send to the SVS, no later than March 31 of each year, the information with respect to corporate governance practices, using as parameters the contents of the Appendix to this regulation. Should the company not have adopted any of them, it must give the reasons why. The information should refer to December 31 of the calendar year prior to

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its dispatch. At the same time, such information shall also be made available to the public on the company’s web site and the information sent to the stock exchanges. The first dispatch and publication of the information required by the regulation should be made no later than June 30, 2013 and refer to March 31, 2013.

Compliance with NYSE Listing Standards on Corporate Governance

The following is a summary of the significant differences between our corporate governance practices and those applicable to domestic issuers under the corporate governance rules of the NYSE.

Independence and Functions of the Audit Committee

Under the NYSE corporate governance rules, all members of the Audit Committee must be independent. We have been subject to this requirement since July 31, 2005. On April 22, 2010, at an ESM, the Company’s bylaws were amended and the Audit Committee was merged with the Directors’ Committee. According to the Company’s bylaws all of the members of this Committee must satisfy the requirements of independence as stipulated by the NYSE. Also, Chilean law requires that the majority of the Directors’ Committee (at least two out of three members) be independent directors. According to Chilean law, a member would not be considered independent if, at any time, within the last 18 months he or she: (i) maintained any relationship of a relevant nature and amount with the company, with other companies of the same group, with its controlling shareholder or with the principal officers of any of them or has been a director, manager, administrator or officer of any of them; (ii) maintained a family relationship with any of the members described in (i) above; (iii) has been a director, manager, administrator or principal officer of a non-profit organization that has received contributions from (i) above; (iv) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of an entity that has provided consulting or legal services for a relevant consideration or external audit services to the persons listed in (i) above; and (v) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of the principal competitors, suppliers or clients. In case there are not sufficient independent directors on the Board to serve on the committee, Chilean Law determines that the independent director nominates the rest of the members of the Committee among the rest of the Board members that do not meet the Chilean law independence requirements. Chilean Law also requires that all publicly held limited liability stock corporations that have a market capitalization of at least UF 1,500,000 (approximately US$ 66 million as of December 31, 2012) and at least 12.5% of its voting shares are held by shareholders that individually control or own less than 10% of such shares, must have at least one independent director and a Directors’ Committee.

Under the NYSE corporate governance rules, the Audit Committee of a U.S. company must perform the functions detailed in, and otherwise comply with the requirements of NYSE Listed Company Manual Rules 303A.06 and 303A.07. Non-U.S. companies have been required to comply with Rule 303A.06 beginning July 31, 2005 but are not required to comply with Rule 303A.07. Since July 31, 2005, we have complied with the independence and the functional requirements of Rule 303A.06. As required by the Sarbanes-Oxley Act (“SOX”) and the NYSE corporate governance rules, on June 29, 2005, Enersis’ Board of Directors created an Audit Committee, composed of three directors who were also members of the Board. As previously mentioned, this Audit Committee was merged into the Directors’ Committee in April 2010. As required by the Company’s bylaws, the members of Directors’ Committee, composed of three members of the Board, should comply with Chilean law, as well as with the criteria and requirements of independence prescribed by SOX, the SEC and the NYSE. As of December 31, 2012, our Directors’ Committee was composed of three independent directors, all of whom met both the independence criteria of Chilean law, the SEC and the NYSE.

Our Directors’ Committee performs the following functions:

•

review of Financial Statements and the Reports of the External Auditors prior to their submission to shareholders’ approval;

•

formulation of the proposal to the Board of Directors for the selection of external auditors and private rating agencies;

•

review of information related to operations by the Company with related parties and/or related to operations in which the Company’s Board members or relevant Executive Officers, their spouses or relatives, and/or legal entities in which Board members or relevant executive officers have worked in the last 18 months, either directly or indirectly;

•

examination of the compensation framework and plans for managers, executive officers and employees;

•

preparation of an Annual Management Report, including its main recommendations to shareholders;

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•

information to the Board of Directors about the convenience of recruiting external auditors to provide non-auditing services, when such services are not prohibited by law, depending on whether such services might affect the external auditors’ independence;

•

oversight of the work of external auditors;

•

review and approval of the annual auditing plan by the external auditors;

•

evaluation of qualifications, independence and quality of the auditing services;

•

elaboration of policies regarding employment of former members of the external auditing firm;

•

review and discussion of problems or disagreements between management and external auditors regarding the auditing process;

•

establishment of procedures for receiving and dealing with complaints regarding accounting, internal control and auditing matters;

•

any other function mandated to the committee by the bylaws, the Board of Directors or the shareholders of the Company.

As of December 31, 2012, Messrs. Leonidas Vial, Rafael Fernández and Hernán Somerville (Chairman) were members of this committee, all of whom satisfied the independence requirements of the NYSE.

Corporate Governance Guidelines

The NYSE’s corporate governance rules require U.S.-listed companies to adopt and disclose corporate governance guidelines. Although Chilean law does not provide for this practice (except for the Manual), the Company has adopted the codes of conduct described above, and at its ESM held in March 2006, approved the inclusion of articles in its bylaws that govern the creation, composition, attributions, functions and compensation of the Directors’ Committee and the Audit Committee.

In order to comply with the new requirements of Law No. 20,382, which amended the Chilean Companies Act, at the ESM of April 22, 2010, the shareholders of the Company approved amendments to the Company’s bylaws, including amendments providing for the merger of the Directors’ and Audit Committees. The Directors’ Committee is currently composed of three members that comply with the SOX independence requirements and the NYSE corporate governance rules. The Committee includes among its functions the duties previously performed by the Audit Committee.

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D.	Employees.

The following table provides the total number of personnel (both permanent and temporary) of our companies for the last three fiscal years:


Company	2012		2011		2010
In Argentina
Endesa Costanera		452		421		376
El Chocón		49		52		50
Edesur		2,948		2,849		2,627
Other businesses (1)		—		—		101

Total personnel in Argentina		3,449		3,322		3,154


In Brazil
Cachoeira Dourada		69		69		65
Endesa Fortaleza		68		72		63
CIEN (2)		65		61		65
Ampla (3)		1,158		1,208		1,224
Coelce		1,544		1,309		1,308
Endesa Brasil		58		47		40
Other businesses (1)		—		—		181

Total personnel in Brazil		2,662		2,766		2,946


In Chile
Endesa Chile		1,102		1,077		603
Pehuenche		3		3		3
Celta		1		1		1
Ingendesa (4)		1		3		503
Túnel El Melón		16		16		16
GasAtacama (5)		94		94		94
HidroAysén (5)		35		35		24
Consorcio Ara—Ingendesa (5)		—		—		14
Enersis		326		318		309
Chilectra (6)		734		712		719
ICT Servicios Informáticos		111		106		100
Other businesses (1)		39		35		668

Total personnel in Chile		2,462		2,400		3,054


In Colombia
Emgesa		517		498		444
Codensa		1,004		985		968
EEC (5)		123		116		115
Other businesses (1)		—		—		444

Total personnel in Colombia		1,644		1,599		1,971


In Peru
Edegel		263		247		244
Edelnor		607		550		553
Other businesses (1)		—		—		342

Total personnel in Peru		870		797		1,139


Total personnel of Enersis and Subsidiaries		11,087		10,884		12,264

(1) Includes CAM and Synapsis, which were sold during 2011.

(2) Includes employees of TESA and CTM who work in Argentina.

(3) Includes En-Brasil Comercio e Serviços S.A.

(4) Includes employees of Ingendesa’s subsidiary in Brazil. During 2011, Ingendesa employees were transferred to Endesa Chile.

(5) Jointly controlled companies, which include personnel on a proportional basis.

(6) Includes Luz Andes S.A. and Empresa Eléctrica de Colina S.A.

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The following table provides the total temporary employees at the Company and its subsidiaries for the past three fiscal years:


Company	2012		Average 2012		2011		2010
In Argentina
Endesa Costanera		—		13.3		55		22
El Chocón		—		0.7		3		—
Edesur		8		15.8		18		16
Other businesses (1)		0		0		0		1

Total temporary personnel in Argentina		8		29.8		76		39


In Brazil
Cachoeira Dourada		—		—		—		—
Endesa Fortaleza		—		—		—		—
CIEN (2)		1		1		1		1
Ampla (3)		—		—		—		—
Coelce		—		0.3		1		18
Endesa Brasil		—		—		—		—
Other businesses (1)		—		—		—		11

Total temporary personnel in Brazil		1		1.3		2		30


In Chile
Endesa Chile		75		83.7		74		4
Pehuenche		—		—		—		—
Celta		—		—		—		—
Ingendesa (4)		—		—		—		—
Túnel El Melón		—		—		—		—
GasAtacama (5)		—		—		—		—
HidroAysén (5)		—		—		—		—
Consorcio Ara—Ingendesa (5)		—		—		—		—
Enersis		—		1.2		1		6
Chilectra (6)		—		—		—		—
ICT Servicios Informáticos		—		—		—		—
Other businesses (1)		—		—		—		—

Total temporary personnel in Chile		75		84.9		75		127


In Colombia
Emgesa		76		67.5		57		14
Codensa		31		25.8		4		2
EEC (5)		—		—		—		—
Other businesses (1)		—		—		—		311

Total temporary personnel in Colombia		107		93.3		61		327


In Peru
Edegel		27		20.5		17		16
Edelnor		68		58.8		47		28
Other businesses (1)		—		—		—		227

Total temporary personnel in Peru		95		79.3		64		271


Total temporary personnel of Enersis and Subsidiaries		286		288.6		278		794

(1) Includes CAM and Synapsis, which were sold during 2011.

(2) Includes TESA and CTM.

(3) Includes En-Brasil Comercio e Serviços S.A.

(4) Includes employees of Ingendesa’s subsidiary in Brazil. During 2011, Ingendesa employees were transferred to Endesa Chile.

(5) Jointly controlled companies, which include personnel on a proportional basis.

(6) Includes Luz Andes S.A. and Empresa Eléctrica de Colina S.A.

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Chile

All Chilean employees who are dismissed for reasons other than misconduct are entitled by law to a severance payment. According to Chilean law, permanent employees are entitled to a basic payment of one-month’s salary for each year (or a six-month portion thereof) worked, subject to a limit of a total payment of no more than 11 months’ pay for employees hired after August 14, 1981. Severance payments to employees hired prior to that date consist of one-month’s salary for each full year worked, not subject to any limitation on the total amount payable. According to Endesa Chile’s collective bargaining agreements, the Company is obligated to make severance payments to all covered employees in cases of voluntary resignation or death in specified amounts that increase according to seniority.

Enersis has two collective agreements, both signed during 2011, which will be in force until July and December 2015. Chilectra has five collective agreements, all of them signed in 2012, which expire in December 2016. Empresa Eléctrica de Colina has one collective agreement, signed in 2011, which expires in October 2015. ICT has one agreement, signed in 2011, which expires in December 2015. Endesa Chile has collective agreements with nine different unions, five of them signed during 2011, which expire between 2013 and 2015. Three of these nine contracts were carried over from Ingendesa.

Argentina

Edesur has two collective agreements signed in April 2011, which expire in March 2014. El Chocón has two collective agreements, one signed during 2011, which expires in December 2016, and another which expired and is still pending negotiation. Endesa Costanera has two collective agreements, which expire in 2014.

Brazil

Ampla has five collective agreements, four of which will expire in September 2013 and one is being negotiated. Coelce has two agreements, one that will expire in October 2013 and another which expired and is still pending negotiation. CIEN has two agreements signed in 2011, one that expires in April 2013 and another which expired in September 2012 and is being negotiated. Cachoeira Dourada has two agreements, one that expires in April 2014 and another which expired in September 2012 and is being negotiated. Endesa Fortaleza has two agreements, one that expires in April 2013 and another which expired in September 2012 and is being negotiated.

Under Brazilian law, collective bargaining agreements cannot last for more than two years.

Colombia

Codensa and Emgesa, each have one collective agreement, both signed during 2011, which will be in force until December 2014. EEC’s collective agreement was expired and is being negotiated.

Peru

Edelnor has four collective agreements, which were signed in 2009 and expired in December 2012. These collective agreements are currently being negotiated. Edegel has one collective agreement, which was signed in 2009 and expires in 2013.

Management believes Enersis’ relationships with trade unions is positive.

E.	Share Ownership.

To the best of the Company’s knowledge, none of Enersis’ directors or officers own more than 0.1% of the shares of the Company. None of Enersis’ directors and officers has any stock options. It is not possible to confirm whether any of our directors or officers has a beneficial, rather than direct, interest in the shares of Enersis. To the best of our knowledge, any share ownership by all of the directors and officers of Enersis, in the aggregate, amount to significantly less than 10% of our outstanding shares.

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Item 7.

Major Shareholders and Related Party Transactions

A.	Major Shareholders.

Enersis has only one class of capital stock and Endesa Spain, our controlling shareholder, has no different voting rights than Enersis’ other shareholders. As of February 28, 2013, our 32,651,166,465 shares of common stock outstanding were held by 7,290 stockholders of record. There were seven record holders of our ADSs as of such date.

It is not practicable for us to determine the number of ADSs or common shares beneficially owned in the United States, as we are not able to ascertain the domicile of the final beneficial holders represented by the seven ADSs record holders. Likewise, we cannot readily determine the domicile of any of our foreign stockholders who hold our common stock, either directly or indirectly.

On February 25, 2013, we began a pre-emptive offering pursuant to the Capital Increase. The subscriptions will not impact the share ownership prior to the satisfaction of the Condition Precedent. For more information regarding the Capital Increase and the Condition Precedent, please see “Introduction — Recent Developments”.

As of February 28, 2013, Endesa Spain beneficially owned 60.6% of the shares of Enersis. Chilean private pension funds, “Administradoras de Fondos de Pensiones,” or AFPs, owned 13.6% in the aggregate. Chilean stockbrokers, mutual funds, insurance companies, foreign equity funds, and other Chilean institutional investors collectively held 12.6% of our equity. ADSs holders owned 11.0% of the equity. The remaining 2.1% was held by 7,125 minority shareholders.

The following table sets forth certain information concerning ownership of the common stock as of February 28, 2013 with respect to each stockholder known to us to own more than 5% of the outstanding shares of common stock:


	Number of Shares Owned		Percentage of Shares Outstanding
Endesa Spain (1)		19,794,583,473		60.6	%

(1)	Endesa Spain’s 60.6% interest is held through Endesa Latinoamérica.

Since June 25, 2009, Enel has been the ultimate controlling shareholder of Enersis by virtue of its 92.06% shareholding in Endesa Spain. Enel is a publicly-traded company headquartered in Italy, primarily engaged in the energy sector, with a presence in 40 countries worldwide, and over 97,000 MW of net installed capacity. It provides service to more than 61 million customers through its electricity and gas businesses.

B.	Related Party Transactions.

Article 146 of Law 18,046 ( the “Chilean Companies Act”) defines related-party transactions as all operations involving the company and any entity belonging to the corporate group, its parent companies, controlling companies, subsidiaries or related companies, board members, managers, administrators, senior officers or company liquidators, including their spouses, some of their relatives and all entities controlled by them, in addition to individuals who may appoint at least one member of the company’s directors or who control 10% or more of voting capital, or companies in which a board member, manager, administrator, senior officer or company liquidator have been serving in the same position within the last 18 months. The law establishes that in the event that these persons fulfill the requirements established by Article 146, such persons must immediately inform the Board of Directors of their related-party nature or such other group as the Board may appoint for that purpose. As required by law, “related-party transactions” must comply with corporate interests, as well as prices, terms and conditions prevailing in the market at the time of their approval. They must also meet all legal requirements, including board acknowledgement and approval of the transaction (excluding the affected directors), approval by the ESM (in some cases, with requisite majority approval) and be approved pursuant to regulatory procedures.

The aforementioned law, which also applies to Enersis’ affiliates, also provides for some exceptions, stating that in certain cases, Board approval would suffice for “related-party transactions, “ pursuant to certain related—party transaction thresholds and when such transactions are conducted in compliance with the related-party policies defined by the company’s board. At its meetings held on December 17, 2009 and April 23, 2010, Enersis’ Board of Directors approved a related-party policy (política de habitualidad) effective as of January 1, 2010. This policy is available on the company’s website.

If an operation is not in compliance with Article 146, this would not affect the operation’s validity, but the company or shareholders may demand compensation from the individual associated with the infringement as provided under law, and to reparation

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for damages. It is our policy that all cash inflows and outflows of our Chilean subsidiaries be managed through our centralized cash management policy. It is a common practice in Chile to transfer surplus funds from one company to another affiliate that has a cash deficit. These operations are carried out through either short-term loans or through structured inter-company loans. Under Chilean laws and regulations, such transactions must be carried out on an arm’s-length basis. Our centralized cash management is more efficient for both financial and tax reasons. All of these operations are subject to the supervision of our Directors’ Committee. As of December 2012, these operations were priced at TIP (a Chilean variable interest rate) + 0.05% per month.

In other countries in which we do business, these inter-company transactions are permitted, but they have adverse tax consequences. Accordingly, we do not similarly manage the cash flows of our non-Chilean subsidiaries.

Our subsidiary, Endesa Chile, has made structured loans to its related parties in Chile, primarily to finance projects. As of December 31, 2012, the outstanding net balance for such loans was US$ 27.5 million, at an interest rate of 3.5%. The largest amounts outstanding during 2012 and 2011 were US$ 38.5 million and US$ 75 million respectively. For the two-year period ending December 31, 2012, Endesa Chile has granted only one loan to a foreign subsidiary, Endesa Costanera, at a spread of 6.0% over LIBOR. The outstanding balance of this loan was US$ 7.1 million as of December 31, 2012. The largest amount outstanding during 2012 and 2011 for such loan was also US$ 7.1 million.

As of the date of this Report, the above-mentioned transactions have not experienced material changes. For more information regarding transactions with related parties, refer to Note 8 to our Consolidated Financial Statements.

C.	Interests of Experts and Counsel.

Not applicable.

Item 8. Financial Information

Consolidated Statements and Other Financial Information.

See “Item 18. Financial Statements” for our Consolidated Financial Statements.

Legal Proceedings

We and our subsidiaries are parties to legal proceedings arising in the ordinary course of business. Management considers that it is unlikely that any loss associated with pending lawsuits will significantly affect the normal development of our business.

For detailed information as of December 31, 2012 on the status of the material pending lawsuits that have been filed against the Company or its subsidiaries, please refer to Note 34.3 to our Consolidated Financial Statements. Since 2009, in relation to the legal proceedings reported in the Notes to the Consolidated Financial Statements, the Company decided to use the criteria of disclosing lawsuits above a minimum threshold of US$ 20 million of potential impact to Enersis, and, in some cases, qualitative criteria according to the materiality of the impact in the conduct of our business. The lawsuits status includes a general description, the process status and the estimate of the amount involved in each lawsuit.

Dividend Policy

The Board generally establishes a definitive dividend payable each year, and attributable to the prior year, which cannot be less than the legal minimum of 30% of annual net income before negative goodwill amortization. As agreed at a meeting held on February 28, 2013, the Board of Directors will propose to the OSM that is expected to be held on April 16, 2013, the payment of a definitive dividend of Ch$ 5.77851 per share for fiscal year 2012, equivalent to a payout ratio of 50% (based on annual net income before negative goodwill amortization). The provisional dividend of Ch$ 1.21538 per share paid in January 2013 will be deducted from the definitive dividend to be paid on May 10, 2013.

The Board of Directors also approved a dividend policy for fiscal year 2013, according to which a provisional dividend will be paid to stockholders equal to 15% of the net income accumulated through September 30, 2013. The Board of Directors will propose a definitive dividend payout equal to 50% of the annual net income for fiscal year 2013. Actual dividend payments will be subject to net profits obtained in each period, as well as to expectations of future profit levels and other conditions that may exist at the time of such dividend declaration. The fulfillment of the aforementioned dividend policy will depend on actual 2013 net income. The proposed dividend policy is subject to the Board of Director’s prerogative to change the amount and timing of the dividend under the circumstances at the time of the payment.

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Currently, there are no restrictions on the ability of Enersis or any of its subsidiaries to pay dividends, other than certain legal restriction of limiting the amount of dividend distributions and in the event of specific circumstances under certain credit agreements, such as: Endesa Costanera, El Chocón, and Endesa Fortaleza may not pay dividends unless they comply with certain financial covenants. In general terms, companies may not pay dividends in case of default on credit agreements. (See “Item 5. Operating and Financial Review and Prospects — B. Liquidity and capital resources” for further detail on Enersis debt instruments).

Stockholders set dividend policies at each subsidiary and affiliate. There are currently no material currency controls which prohibit Enersis from repatriating the dividend payments from its non-Chilean principal subsidiaries and affiliates.

The Company pays dividends to shareholders with a record date of five business days before the payment date. Holders of ADS on the applicable record dates will be entitled to participate in all future dividends.

Dividends

The table below sets forth, for each of the years indicated, the per share amounts of dividends distributed by the Company and the amount of dividends distributed per ADS (one ADS represents 50 shares of common stock) in U.S. dollars. See “Item 10. Additional Information — D. Exchange Controls.”


Year	Nominal Ch$(1)		US$ per ADS (2)
2012		5.75		0.60
2011		7.45		0.72
2010		4.64		0.50
2009		7.02		0.69
2008		4.95		0.39

(1)	This chart details dividends paid in a given year, and not the dividends accrued in that year. These dividends may have been accrued during the prior year or the same year in which they were paid. These amounts do not reflect reduction for any applicable Chilean withholding tax.

(2)	The U.S. dollar per ADS amount has been calculated by applying the Observed Exchange Rate for December 31 of each year, to the Chilean peso amount. One ADS represents 50 shares of common stock.

For a discussion of Chilean withholding taxes and access to the formal currency market in Chile in connection with the payment of dividends and sales of ADSs and the underlying common stock, see “Item 10. Additional Information — E. Taxation” and “Item 10. Additional Information — D. Exchange Controls.”

B.	Significant Changes.

None.

Item 9. The Offer and Listing

A.	Offer and Listing Details.

Market Price Information

The shares of our common stock currently trade on Chilean, United States and Spanish exchanges.

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The table below shows, for the periods indicated, high and low closing prices in Chilean pesos on the Santiago Stock Exchange, and high and low closing prices of the ADSs in U.S. dollars as reported by the NYSE.


	Santiago Stock Exchange (1)				U.S. Stock Exchanges (2)
	Ch$ per share				US$ per ADS
	High		Low		High		Low
2013		189.80		174.01		19.97		18.25
February		189.80		176.52		19.97		18.51
January		188.00		174.01		19.89		18.25

2012		203.50		150.10		20.87		15.50
December		176.00		161.50		18.46		16.81
November		169.00		154.30		17.59		16.23
October		167.70		154.00		17.45		16.16
September		159.50		151.00		16.87		16.00
4th Quarter		176.00		154.00		18.46		16.16
3rd Quarter		195.74		150.10		19.98		15.50
2nd Quarter		201.88		171.50		20.84		17.00
1st Quarter		203.50		171.50		20.87		17.42

2011		221.10		169.00		23.48		15.81
4th Quarter		200.00		169.00		20.32		15.81
3rd Quarter		217.50		170.01		23.48		16.47
2nd Quarter		219.30		192.00		23.31		20.32
1st Quarter		221.10		180.00		23.40		18.87

2010		245.00		195.00		25.42		17.50
4th Quarter		244.00		213.02		25.42		22.45
3rd Quarter		239.11		212.00		24.16		19.62
2nd Quarter		223.00		195.00		20.98		17.50
1st Quarter		245.00		207.99		23.88		19.33

2009		231.50		162.50		22.99		12.76

(1)	Source: Santiago Stock Exchange.

(2)	Source: NYSENET. Enersis’ ADSs composite figures include transactions in all U.S. stock exchanges. One ADS = 50 shares of common stock.

On the last trading day in 2012, the common stock price closed at Ch$ 175.82 per share on the Santiago Stock Exchange and the ADS closed at US$ 18.22 on the NYSE.

As of February 28, 2013, the common stock price closed at Ch$ 180.72 per share on the Santiago Stock Exchange and the ADS closed at US$ 18.59 on the NYSE.

On December 20, 2012, our shareholders approved an increase in our authorized capital through the issuance of 16,441,606,297 additional shares of common stock in connection with the Capital Increase. For more information regarding the Capital Increase, please see “Introduction — Recent Developments”.

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The market prices of our common stock on the Santiago Stock Exchange and the ADSs on the U.S. Stock Exchanges for the first trading day in the most recent six months before the Capital Increase are shown below, expressed in Chilean pesos and U.S. dollars, respectively:


	Santiago Stock Exchange (1)	U.S. Stock Exchanges (2)
	Ch$ per share (3)	US$ per ADS (3)

March 1, 2013	180.90	18.70
February 1, 2013	188.00	19.85
January 1, 2013	174.63	18.29
December 1, 2012	165.86	17.08
November 1, 2012	165.50	17.40
October 1, 2012	159.01	16.84

(1)	Source: Santiago Stock Exchange.

(2)	Source: NYSENET. Enersis’ ADSs composite figures include transactions in all U.S. stock exchanges. One ADS = 50 shares of Common Stock.

(3)	Represents the closing price.

The closing prices of our common stock on the Santiago Stock Exchange and the ADSs on the U.S. Stock Exchanges on December 19, 2012 (the last trading day before the announcement of the approval by shareholders of the Capital Increase) were Ch$ 174.38 and US$ 18.27, respectively.

B.	Plan of Distribution.

Not applicable.

C.	Markets.

In Chile, the Company’s stock is traded on three stock exchanges: the Santiago Stock Exchange, the Electronic Stock Exchange and the Valparaíso Stock Exchange. The largest exchange in the country, the Santiago Stock Exchange, was established in 1893 as a private company. Its equity consists of 48 shares held by 44 stockholders as of the date of this Report. As of December 31, 2012, 225 companies had shares listed on the Santiago Stock Exchange. For the year ended 2012, the Santiago Stock Exchange accounted for 89.1% of Enersis’ total equity traded in Chile and amounted to 5,564,254,752 shares. In addition, approximately 9.7% of Enersis’ equity trading was conducted on the Electronic Stock Exchange, an electronic trading market that was created by banks and non-member brokerage houses, and 1.2% was traded on the Valparaíso Stock Exchange.

Equities, closed-end funds, fixed-income securities, short-term and money market securities, gold and U.S. dollars are traded on the Santiago Stock Exchange. The Santiago Stock Exchange also trades U.S. dollar futures and stock index futures. Securities are traded primarily through an open voice auction system; a firm offers system or the daily auction. Trading through the open voice system occurs on each business day from 9:30 a.m. to 4:00 p.m., during local standard time, and from 9:30 a.m. to 5:00 p.m. during daylight savings time, which differs from New York City time by up to two hours, depending on the season. The Santiago Stock Exchange has an electronic trading system called Telepregón, which operates continuously from 9:30 a.m. to 4:00 p.m. during local standard time, and from 9:00 a.m. to 5:00 p.m. during daylight savings time, on each business day. During local standard time, electronic auctions may be conducted four times a day, at 10:30 a.m., 11:30 a.m., 1:30 p.m., and 3:30 p.m. During daylight savings time there is an additional electronic auction at 4:30 p.m. More than 99% of the auctions and transactions take place electronically.

There are two share price indexes on the Santiago Stock Exchange, the General Shares Price Index, or IGPA, and the Selected Shares Price Index, or IPSA. The IGPA is calculated using the prices of shares that are traded at least 5% of the trading days of a year, with a total annual transactions exceeding UF 10,000 (US$ 0.48 million as of December 31, 2012) and a free float of at least 5%. The IPSA is calculated using the prices of the 40 shares with higher amounts traded, on a quarterly basis, with market capitalization above US$ 200 million and a free float at least 5%. The shares included in the IPSA and IGPA are weighted according to the weighted value of the shares traded. Enersis has been included in the IPSA since the last quarter of 1988, while Endesa Chile has been included since its privatization process in 1987.

Shares of our common stock have traded in the United States in the form of ADSs on the New York Stock Exchange (NYSE) since October 1993, under the ticker symbol “ENI”. Each ADS represents 50 shares of common stock, with the ADSs in turn

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evidenced by American Depositary Receipts (ADRs). The ADRs are outstanding under the Second Amended and Restated Deposit Agreement dated as of September 30, 2010 among us, Citibank, N.A. as Depositary, and the holders and beneficial owners from time to time of ADRs issued thereunder. Only persons in whose names ADRs are registered on the books of the Depositary are treated by the Depositary as owners of ADRs.

As of February 28, 2013, ADRs evidencing 71,855,207 ADSs (equivalent to 3,592,760,350 common shares) were outstanding, representing 11.0% of the total number of outstanding shares. It is not practicable for the Company to determine the proportion of ADSs beneficially owned by U.S. final beneficial holders. Trading of our shares on the NYSE and other exchanges during 2012 amounted to approximately 136 million ADS, which in turn was equivalent to US$ 2,457 million.

The NYSE is open for trading Monday through Friday from 9:30 am to 4:00 pm, with the exception of holidays declared by the NYSE in advance. On the trading floor, the NYSE trades in a continuous auction format, where traders can execute stock transactions on behalf of investors. Specialist broker acts as an auctioneer in an open outcry auction market to bring buyers and sellers together and to manage the actual auction. Customers can also send orders for immediate electronic execution, or route orders to the floor for trade in the auction market. The NYSE works with U.S. regulators like the Securities and Exchange Commission (SEC) and the Commodity Futures Trading Commission (CFTC) to coordinate risk management measures in the electronic trading environment through the implementation of mechanisms like circuit breakers and liquidity replenishment points.

Shares of Enersis were first listed and began trading on the Bolsa de Valores Latinoamericanos de la Bolsa de Madrid, or Latibex, as of December 2001, under the ticker symbol “XENI”. Until April 2011, the trading unit represented 50 common shares (the same unit conversion of 50:1 as an ADS), but since May 2011 the equivalence changed to a 1:1 ratio. Santander Investment S.A. acts as the liaison entity, and the Banco Santander-Chile as the Depositary Bank in Chile. Trading of our shares on the Latibex during 2012 amounted to approximately 6.4 million units, which in turn was equivalent to € 1.8 million. The stock closed at € 0.27 on the last 2012 trading day.

The following table contains information regarding the amount of common stocks and the percentage traded per market during 2012:


	Enersis
	N° of common stocks		%
Market
United States (ADS = 50 common stocks)		6,786,617,250		52.0%
NYSE		2,819,525,100		21.6	%
Other exchanges		3,967,092,150		30.4	%
Chile (1)		6,242,751,527		47.9%
Spain (2)		6,402,927		0.1%
Total		13,035,771,704		100.0%

(1)

Includes Santiago Stock Exchange, Electronic Stock Exchange and Valparaíso Stock Exchange.

(2)

Latibex.

For further information see “Item 9. The Offer and Listing — A. Offer and Listing Details — Market Price Information.”

D.	Selling Shareholders.

Not applicable.

E.	Dilution.

Not applicable.

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F.	Expense of the Issue.

Not applicable.

Item 10. Additional Information

A.	Share Capital.

Not applicable.

B.	Memorandum and Articles of Association.

Description of Share Capital

Set forth below is certain information concerning our share capital and a brief summary of certain significant provisions of our bylaws and Chilean law.

General

Shareholders’ rights in Chilean companies are governed by the company’s bylaws, which serve the same purpose as the articles or certificate of incorporation and the bylaws of a company incorporated in the United States, and by Law 18,046 (the Chilean Companies Act). In addition, D.L. 3500, or the Pension Funds’ System Law, which permits the investment by Chilean pension funds in stock of qualified companies, indirectly affects corporate governance and prescribes certain rights of shareholders. In accordance with the Chilean Companies Act, legal actions by shareholders to enforce their rights as shareholders of the company must be brought in Chile in arbitration proceedings or, at the option of the plaintiff, before Chilean courts. Members of the board of directors, managers, officers and principal executives of the company, or shareholders that individually own shares with a book value or stock value higher that UF 5,000 (US$ 237,944 as of December 31, 2012) do not have the option to bring the procedure to the courts.

The Chilean securities markets are principally regulated by the Superintendency of Securities and Insurance, or SVS, under Law 18,045 (the Securities Market Law) and the Chilean Companies Act. These two laws provide for disclosure requirements, restrictions on insider trading and price manipulation, and protection of minority shareholders. The Securities Market Law sets forth requirements for public offerings, stock exchanges and brokers, and outlines disclosure requirements for companies that issue publicly offered securities. The Chilean Companies Act and the Securities Market Law, both as amended, provide rules regarding takeovers, tender offers, transactions with related parties, qualified majorities, share repurchases, directors’ committee, independent directors, stock options and derivative actions.

Public Register

Enersis is a publicly held stock corporation incorporated under the laws of Chile. Enersis was constituted by public deed issued on June 19, 1981 by the Santiago Notary Public, Mr. Patricio Zaldívar M. Its existence was approved by SVS Resolution 409-S of July 17, 1981 and it was registered on July 21, 1981 in the Commercial Registrar (Registro de Comercio del Conservador de Bienes Raíces y Comercio de Santiago), on pages 13099 No. 7269. Enersis is registered with the SVS and its entry number is 0175. Enersis is also registered with the United States Securities and Exchange Commission and its commission file number is 001-12440.

Reporting Requirements Regarding Acquisition or Sale of Shares

Under Article 12 of the Securities Market Law and General Rule 269 of the SVS, certain information regarding transactions in shares of a publicly held stock corporation or in contracts or securities whose price or results depend on or are conditioned in whole or in part on the price of such shares must be reported to the SVS and the Chilean stock exchanges. Since American Depositary Shares (ADS) are deemed to represent the shares of common stock underlying the American Depositary Receipts (ADRs), transactions in ADRs will be subject to these reporting requirements and those established in Circular 1375 of the SVS. Shareholders of publicly held stock corporations are required to report to the SVS and the Chilean stock exchanges:

•

any direct or indirect acquisition or sale of shares made by a holder who owns, directly or indirectly at least 10% of a publicly held stock corporation’s subscribed capital;

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•

any direct or indirect acquisition or sale of contracts or securities whose price or results depend on or are conditioned in whole or in part on the price of shares made by a holder who owns, directly or indirectly at least 10% of a publicly held stock corporation’s subscribed capital;

•

any direct or indirect acquisition or sale of shares made by a holder who, due to an acquisition of shares of such publicly held stock company, results in the holder acquiring, directly or indirectly, at least 10% of a publicly held stock company’s subscribed capital; and

•

any direct or indirect acquisition or sale of shares in any amount, made by a director, receiver, principal executive, general manager or manager of a publicly held stock company.

In addition, majority shareholders of a publicly held stock corporation must inform the SVS and the Chilean stock exchanges if such transactions are entered into with the intention of acquiring control of the company or if they are making a passive financial investment instead.

Under Article 54 of the Securities Market Law and General Rule 104 enacted by the SVS, any person who directly or indirectly intends to take control of a publicly held stock corporation must disclose this intent to the market at least ten business days in advance of the proposed change of control and, in any event, as soon as the negotiations for the change of control have taken place or reserved information of the publicly held stock corporation has been provided.

Corporate Objectives and Purposes

Article 4 of our bylaws states that our corporate objectives and purposes are, among other things, to conduct the exploration, development, operation, generation, distribution, transmission, transformation, or sale of energy in any form, directly or through other companies, as well as to provide engineering-consultancy services related to these objectives, in Chile and abroad and to participate in the telecommunications business.

Board of Directors

Our Board of Directors is comprised of seven members who are appointed by shareholders at the OSM of the Company and are elected for a period of three years, at the end of which they will be re-elected or replaced.

The seven directors elected at the OSM are the seven individual nominees who receive the highest majority of the votes. Each shareholder may vote his shares in favor of one nominee or may apportion his shares among any number of nominees. The effect of these voting provisions is to ensure that a shareholder owning more than 12.5% of our shares is able to elect a member of the Board.

The compensation of the directors is set annually at the OSM. See “Item 6. Directors, Senior Management and Employees — B. Compensation.”

Agreements entered into by Enersis with related parties can only be executed when such agreements serve the interest of the Company, and their price, terms and conditions are consistent with prevailing market conditions at the time of their approval and comply with all the requirements and procedures indicated in Article 147 of the Chilean Companies Act.

Certain Powers of the Board of Directors

Our bylaws provide that every agreement or contract that the Company enters into with its controlling shareholder, its directors or executives, or with their related parties, must be previously approved by two thirds of the Board of Directors and be included in the Board meetings and must comply with the provisions of the Chilean Companies Act.

Our bylaws do not contain provisions relating to:

•

the directors’ power, in the absence of an independent quorum, to vote on compensation for themselves or any members of their body;

•

borrowing powers exercisable by the directors and how such borrowing powers can be varied;

•

retirement or non-retirement of directors under an age limit requirement; or

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•

number of shares, if any, required for directors’ qualification.

Certain Provisions Regarding Shareholder Rights

As of the date of the filing of this Report, Enersis’ capital is comprised of only one class of shares, all of which are ordinary shares and have the same rights.

Our bylaws do not contain any provisions relating to:

•

redemption provisions;

•

sinking funds; or

•

liability for capital calls by the Company.

Under Chilean law, the rights of holders of stock of the Company may only be changed by an amendment to the bylaws that comply with the requirements explained below under “Item 10. Additional Information — B. Memorandum and Articles of Association. — Shareholders’ Meetings and Voting Rights.”

Capitalization

Under Chilean law, only the shareholders of a company acting at an ESM have the power to authorize a capital increase. When an investor subscribes for shares, these are officially issued and registered under his name, and the subscriber is treated as a shareholder for all purposes, except receipt of dividends and for return of capital in the event that the shares have been subscribed but not paid for. The subscriber becomes eligible to receive dividends only for the shares that he has actually paid for or, if he has paid for only a portion of such shares, the pro rata portion of the dividends declared with respect to such shares unless the company’s bylaws provide otherwise. If a subscriber does not fully pay for shares for which he has subscribed on or prior to the date agreed upon for payment, notwithstanding the actions intended by the company to collect payment, the company is entitled to auction the shares on the stock exchange where such shares are traded, for the account and risk of the debtor, the number of shares held by the debtor necessary for the company to pay the outstanding balances and disposal expenses. However, until such shares are sold at auction, the subscriber continues to possess all the rights of a shareholder, except the right to receive dividends and return of capital. The chief executive officer or the person replacing him will reduce in the shareholders’ register the number of shares in the name of the debtor shareholder to the number of shares that remain, deducting the shares sold by the company and settling the debt in the amount necessary to cover the result of such disposal after the corresponding expenses. When there are authorized and issued shares for which full payment has not been made within the period fixed by shareholders at the same ESM at which the subscription was authorized (which in no case may exceed three years from the date of such meeting), this shall be reduced in the non-subscribed amount until that date. With respect to the shares subscribed and not paid following the term mentioned above, the Board must proceed to collect payment, unless the shareholders’ meeting had authorized (by two thirds of the voting shares) to reduce the company’s capital to the amount effectively collected, in which case the capital shall be reduced by force of law to the amount effectively paid. Once collection actions have been exhausted, the Board should propose to the shareholders’ meeting the approval by simple majority of the write-off of the outstanding balance and the reduction of capital to the amount effectively recovered.

As of December 31, 2012, the subscribed and fully paid capital of the Company totaled Ch$ 2,825 billion and consisted of 32,651,166,465 shares.

On December 20, 2012, our shareholders approved an increase in our authorized capital through the issuance of 16,441,606,297 additional shares of Common Stock in connection with the Capital Increase. If subscribed during the rights offering period, such shares would be issued for Ch$ 173 per share (Ch$ 8,650 per ADS) or Ch$ 2,844 billion if fully subscribed. The rights offering was initiated on February 25, 2013 and any subscriptions will not impact our capitalization prior to the satisfaction of the Condition Precedent. If the Condition Precedent is satisfied, Endesa Spain will subscribe for a total of 9,967,630,058 shares, in proportion to its holdings, and minority shareholders may subscribe for up to a total of 6,473,976,239 shares for cash. As of the date of this Report, the Condition Precedent has not been satisfied. If the Condition Precedent is satisfied and the Capital Increase is subscribed in full, the subscribed and fully paid capital of the Company would total approximately Ch$ 5,669 billion and consist of 49,092,772,762 shares. For more details regarding the Capital Increase and the Condition Precedent, please see “Introduction — Recent Developments”.

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Preemptive Rights and Increases of Share Capital

The Chilean Companies Act requires Chilean companies to grant shareholders preemptive rights to purchase a sufficient number of shares to maintain their existing ownership percentage of such company whenever such company issues new shares.

Under Chilean law, preemptive rights are exercisable or freely transferable by shareholders during a 30-day period following the day the capital increase is made public. The options to subscribe for shares in capital increases of the company or of any other securities convertible into shares or that confer future rights over these shares, should be offered, at least once, to the shareholders pro rata to the shares held registered in their name at midnight on the fifth business day prior to the date of the start of the preemptive rights period. The preemptive rights offering and the start of the 30-day period for exercising them shall be communicated through the publication of a prominent notice, at least once, in the newspaper that should be used for notifications of shareholders’ meetings. During such 30-day period, and for an additional period of up to 30 days immediately following the initial 30-day period, publicly held stock corporations are not permitted to offer any unsubscribed shares to third parties on terms which are more favorable than those offered to their shareholders. At the end of the second 30-day period, a Chilean publicly held stock corporation is authorized to sell non-subscribed shares to third parties on any terms, provided they are sold on one of the Chilean stock exchanges.

Shareholders’ Meetings and Voting Rights

An OSM must be held within the first four months following the end of our fiscal year. The last OSM was held on April 26, 2012. An ESM may be called by the board of directors when deemed appropriate, when requested by shareholders representing at least 10% of the issued shares with voting rights or by the SVS. To convene an OSM, or an ESM, notice must be given three times in a newspaper located in our corporate domicile. The newspaper designated by our shareholders is El Mercurio de Santiago. The first notice must be published not less than 15 days and no more than 20 days in advance of the scheduled meeting. Notice must also be mailed to each shareholder, to the SVS and to the Chilean stock exchanges.

The OSM shall be held on the day stated in the notice and should remain in session until having exhausted all the matters stated in the notice. However, once constituted, upon the proposal of the chairman or shareholders representing at least 10% of the shares with voting rights, the majority of the shareholders present may agree to suspend it and to continue it within the same day and place, no new constitution of the meeting nor qualification of powers being necessary, recorded in one set of minutes. Only those shareholders who were present or represented may attend the recommencement of the meeting with voting rights.

Under Chilean law, a quorum for a shareholders’ meeting is established by the presence, in person or by proxy, of shareholders representing at least a majority of the issued shares with voting rights of a company. If a quorum is not present at the first meeting, a reconvened meeting can take place at which the shareholders present are deemed to constitute a quorum regardless of the percentage of the shares represented. The second meeting must take place within 45 days following the scheduled date for the first meeting. Shareholders’ meetings adopt resolutions by the affirmative vote of a majority of those shares present or represented at the meeting. An ESM must be called to take the following actions:

•

a transformation of the company into a form other than a publicly held stock corporation under the Chilean Companies Act, a merger or split-up of the company;

•

an amendment to the term of duration or early dissolution of the company;

•

a change in the corporation’s domicile;

•

a decrease of corporate capital;

•

an approval of capital contributions in kind and non-monetary assessments;

•

a modification of the authority reserved to shareholders or limitations on the board of directors;

•

a reduction in the number of members of the board of directors;

•

a disposition of 50% or more of the assets of the corporation, whether it includes disposition of liabilities or not, as well as the approval or the amendment of the business plan which contemplates the disposition of assets in an amount greater that such percentage;

157

•

the disposition of 50% or more of the assets of a subsidiary, as long as such subsidiary represents at least 20% of the assets of the corporation, as well as any disposition of its shares that results in the parent company losing its position as controller;

•

the form of distributing corporate benefits;

•

issue of guarantees for third-party liabilities which exceed 50% of the assets, except when the third party is a subsidiary of the company, in which case approval of the board of directors is deemed sufficient;

•

the purchase of the corporation’s own shares;

•

others established by the bylaws or the laws;

•

certain remedies for the nullification of the corporate bylaws;

•

inclusion in the bylaws of the right to purchase shares from minority shareholders, when the controlling shareholders reaches 95% of the company’s shares by means of a tender offer for all of the company’s shares, where at least 15% of the shares have been acquired from unrelated shareholders;

•

approval or ratification of acts or contracts with related parties.

Regardless of the quorum present, the vote required for any of the actions above is at least two-thirds of the outstanding shares with voting rights.

Bylaw amendments for the creation of a new class of shares, or an amendment to or an elimination of those classes of shares that already exist, must be approved by at least two-thirds of the outstanding shares of the affected series.

Chilean law does not require a publicly held stock corporation to provide its shareholders the same level and type of information required by the securities laws regarding the solicitation of proxies. However, shareholders are entitled to examine the books of a publicly held stock corporation within the 15-day period before its scheduled OSM. Under Chilean law, a notice of a shareholders meeting listing matters to be addressed at the meeting must be mailed at least 15 days prior to the date of such meeting, and, an indication of the way complete copies of the documents that support the matters submitted for voting can be obtained, which must also be made available to shareholders on the Company’s website. In the case of an OSM, the annual report of the Company’s activities, which includes audited financial statements, must also be made available to shareholders and published on the Company’s website at: www.enersis.cl.

The Chilean Companies Act provides that, upon the request by the Directors’ Committee or by shareholders representing at least 10% of the issued shares with voting rights, a Chilean company’s annual report must include, in addition to the materials provided by the board of directors to shareholders, such shareholders’ comments and proposals in relation to the company’s affairs. In accordance with article 136 of the Chilean Companies Regulation (“Reglamento de Sociedades Anónimas”), the shareholder(s) holding or representing 10% or more of the shares issued with voting rights, may:

•

make comments and proposals relating to the progress of the corporate businesses in the corresponding year, no shareholder being able to make individually or jointly more than one presentation. These observations should be presented in writing to the company concisely, responsibly and respectfully, and the respective shareholder(s) should state their willingness for these to be included as an appendix to the annual report. The board shall include in an appendix to the annual report of the year a faithful summary of the pertinent comments and proposals the interested parties had made, provided they are presented during the year or within 30 days after its ending;

•

make comments and proposals on matters that the board submits for the knowledge or voting of the shareholders. The board shall include a faithful summary of those comments and proposals in all information it sends to shareholders, provided the shareholders’ proposal is received at the offices of the company at least 10 days prior to the date of dispatch of the information by the company. The shareholders should present to the company their comments and proposals, expressing their willingness for these to be included in the appendix to the respective annual report or in information sent to shareholders, as the case may be. The observations referred to in this Article may be made separately by each shareholder holding 10% or more of the shares issued with voting rights or shareholders who together hold that percentage, who should act as one.

158

Similarly, the Chilean Companies Act provides that whenever the board of directors of a publicly held stock corporation convenes an OSM and solicits proxies for the meeting, or circulates information supporting its decisions or other similar material, it is obligated to include the pertinent comments and proposals that may have been made by the Directors’ Committee or by shareholders owning 10% or more of the shares with voting rights who request that such comments and proposals be so included.

Only shareholders registered as such with Enersis as of 11:59 p.m. on the fifth business days prior to the date of a meeting are entitled to attend and vote their shares. A shareholder may appoint another individual, who does not need to be a shareholder, as his proxy to attend the meeting and vote on his behalf. Proxies for such representation shall be given for all the shares held by the owner. The proxy may contain specific instructions to approve, reject or abstain with respect to any of the matters submitted for voting at the meeting and which were included in the notice. Every shareholder entitled to attend and vote at a shareholders’ meeting shall have one vote for every share subscribed.

There are no limitations imposed by Chilean law or the company’s bylaws on the right of nonresidents or foreigners to hold or vote shares of common stock. However, the registered holder of the shares of common stock represented by ADSs, and evidenced by outstanding ADSs, is the custodian of the Depositary, currently Banco Santander-Chile, or any successor thereto. Accordingly, holders of ADSs are not entitled to receive notice of meetings of shareholders directly or to vote the underlying shares of common stock represented by ADS directly. The Deposit Agreement contains provisions pursuant to which the Depositary has agreed to solicit instructions from registered holders of ADSs as to the exercise of the voting rights pertaining to the shares of common stock represented by the ADSs. Subject to compliance with the requirements of the Deposit Agreement and receipt of such instructions, the Depositary has agreed to endeavor, insofar as practicable and permitted under Chilean law and the provisions of the bylaws, to vote or cause to be voted (or grant a discretionary proxy to the Chairman of the Board of Directors of the company or to a person designated by the Chairman of the Board of Directors of the Company to vote) the shares of common stock represented by the ADSs in accordance with any such instruction. The Depositary shall not itself exercise any voting discretion over any shares of common stock underlying ADSs. If no voting instructions are received by the Depositary from a holder of ADSs with respect to the shares of common stock represented by the ADSs, on or before the date established by the Depositary for such purpose, the shares of common stock represented by the ADS, may be voted in the manner directed by the Chairman of the Board of the Company, or by a person designated by the Chairman of the Board of the Company, subject to limitations set forth in the Deposit Agreement.

Dividends and Liquidation Rights

According to the Chilean Companies Act, unless otherwise decided by unanimous vote of its issued shares eligible to vote, all companies must distribute a cash dividend in an amount equal to at least 30% of their consolidated net income, before amortization and negative goodwill for each year (calculated according to the local accounting rules applicable to the Company when preparing financial statements to be submitted to the SVS), unless and except to the extent the Company has carried forward losses. The law provides that the board of directors must agree to the dividend policy and inform such policy to the shareholders at the OSM.

Any dividend in excess of 30% of net income may be paid, at the election of the shareholder, in cash, in Enersis shares or in shares of publicly held corporations held by Enersis. Shareholders who do not expressly elect to receive a dividend other than in cash are legally presumed to have decided to receive the dividend in cash.

Dividends which are declared but not paid within the appropriate time period set forth in the Chilean Companies Act (as to minimum dividends, 30 days after declaration; as to additional dividends, the date set for payment at the time of declaration) are adjusted to reflect the change in the value of UF, from the date set for payment to the date such dividends are actually paid. Such dividends also accrue interest at the then prevailing rate for UF-denominated deposits during such period. The right to receive a dividend lapses if it is not claimed within five years from the date such dividend is payable. Payments not collected in such period are transferred for the benefit of the Fire Department, formed by volunteers.

In the event of a liquidation of Enersis, the holders of shares would participate in the assets available in proportion to the number of paid-in shares held by them, after payment to all creditors.

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Approval of Financial Statements

The Board of Directors is required to submit Enersis’ consolidated financial statements to the shareholders annually for their approval. If the shareholders by a vote of a majority of shares present (in person or by proxy) at the shareholders’ meeting reject the financial statements, the Board of Directors must submit new financial statements no later than 60 days from the date of such meeting. If the shareholders reject the new financial statements, the entire Board of Directors is deemed removed from office and a new board is elected at the same meeting. Directors who individually approved such financial statements are disqualified for reelection for the following period. Our shareholders have never rejected the financial statements presented by the Board of Directors.

Change of Control

The Capital Markets Law establishes a comprehensive regulation related to tender offers. The law defines a tender offer as the offer to purchase shares of companies which publicly offer their shares or securities convertibles into shares and which offer is made to shareholders to purchase their shares under conditions which allow the bidder to reach a certain percentage of ownership of the company within a fixed period of time. These provisions apply to both voluntary and hostile tender offers.

Acquisition of Shares

There are no provisions in our bylaws that discriminate against any existing or prospective holder of shares as a result of such shareholder owning a substantial number of shares. However, no person may directly or indirectly own more than 65% of the outstanding shares of our stock. The foregoing restriction does not apply to the depositary as record owner of shares represented by ADRs, but it does apply to each beneficial ADS holder. Additionally, our bylaws prohibit any shareholder from exercising voting power with respect to more than 65% of the common stock owned by such shareholder or on behalf of others representing more than 65% of the outstanding issued shares with voting rights.

Right of Dissenting Shareholders to Tender Their Shares

The Chilean Companies Act provides that upon the adoption of any of the resolutions enumerated below at a meeting of shareholders, dissenting shareholders acquire the right to withdraw from the company and to compel the company to repurchase their shares, subject to the fulfillment of certain terms and conditions. In order to exercise such withdrawal rights, holders of ADRs must first withdraw the shares represented by their ADRs pursuant to the terms of the deposit agreement.

“Dissenting” shareholders are defined as those who at a shareholders’ meeting vote against a resolution that results in the withdrawal right, or who if absent from such meeting, state in writing their opposition to the respective resolution, within the 30 days following the shareholders’ meeting. Shareholders present or represented at the meeting and who abstain in exercising their voting rights, shall not be considered as dissenting. The right to withdraw should be exercised for all the shares that the dissenting shareholder had registered in their name on the date on which the right is determined to participate in the meeting at which the resolution is adopted that motivates the withdrawal and which remains on the date on which their intention to withdraw is communicated to the company. The price paid to a dissenting shareholder of a publicly held stock corporation whose shares are quoted and actively traded on one of the Chilean stock exchanges, is the greater of (i) the weighted average of the sales prices for the shares as reported on the Chilean stock exchanges on which the shares are quoted for the two-month period between the ninetieth and the thirtieth day before the shareholders’ meeting giving rise to the withdrawal right, and (ii) the market price resulting from the average price of transactions on such day. If, because of the volume, frequency, number and diversity of the buyers and sellers, the SVS determines that the shares are not actively traded on a stock exchange, the price paid to the dissenting shareholder shall be the book value. Book value for this purpose shall equal paid capital plus reserves and profits, less losses, divided by the total number of subscribed shares, whether entirely or partially paid. For the purpose of making this calculation, the last consolidated statements of financial position is used, as adjusted to reflect inflation up to the date of the shareholders’ meeting which gave rise to the withdrawal right.

Article 126 of the Chilean Companies Regulation establishes that in cases where the right to withdraw arises, the company shall be obliged to inform the shareholders of this situation, the value per share that will be paid to shareholders exercising their right to withdraw and the term for exercising it. Such information should be given to shareholders at the same meeting at which the resolutions are adopted giving rise to the right of withdrawal, prior to its voting. A special communication should be given to the shareholders with rights, within two days following the date on which the rights to withdraw are born. In the case of publicly held companies, such information shall be communicated by a prominent notice in a newspaper with a wide national circulation and on its web site, plus a written communication addressed to the shareholders with rights at the address they have registered with the company. The notice of the shareholders meeting that should pronounce on a matter that could originate withdrawal rights should mention this circumstance.

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The resolutions that result in a shareholder’s right to withdraw include, among others, the following:

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the transformation of the company into an entity which is not a publicly held stock corporation governed by Chilean Companies Act;

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the merger of the company with another company;

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disposition of 50% or more of the assets of the corporation, whether it includes disposition of liabilities or not, as well as the approval or the amendment of the business plan which contemplates the disposition of assets in an amount greater than such percentage;

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issue of guarantees for third parties’ liabilities which exceed 50% of the assets (if the third party is a subsidiary of the company, the approval of the board of directors is sufficient);

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the creation of preferential rights for a class of shares or an amendment to the existing ones. In this case the right to withdraw only accrues to the dissenting shareholders of the class or classes of shares adversely affected;

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certain remedies for the nullification of the corporate bylaws; and

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such other causes as may be established by the law or by the company’s bylaws.

Investments by AFPs

The Pension Funds’ System Law permits AFPs to invest their funds in companies that are subject to Title XII and, subject to greater restrictions, in other companies. The determination of which stocks may be purchased by AFPs is made by the Risk Classification Committee. The Risk Classification Committee establishes investment guidelines and is empowered to approve or disapprove those companies that are eligible for AFP investments. Except for the period from March 2003 to March 2004, Enersis has been a Title XII Company since 1985 and is approved by the Risk Classification Committee.

Title XII companies are required to have bylaws that limit the ownership of any shareholder to a specified maximum percentage, bylaws that require that certain actions be taken only at a meeting of the shareholders and bylaws that give the shareholders the right to approve certain investment and financing policies.

Registrations and Transfers

Shares issued by Enersis are registered with an administrative agent named DCV Registros S.A. This entity is responsible for Enersis’ shareholders registry as well. In case of jointly owned shares, an attorney-in-fact must be appointed to represent the joint owners in dealing with Enersis.

C.	Material Contracts.

None.

D.	Exchange Controls.

The Central Bank of Chile is responsible for, among other things, monetary policies and exchange controls in Chile. Currently applicable foreign exchange regulations are set forth in the Compendium of Foreign Exchange Regulations (the “Compendium”) approved by the Central Bank of Chile in 2002. Appropriate registration of a foreign investment in Chile permits the investor access to the Formal Exchange Market. Foreign investments can be registered with the Foreign Investment Committee under D.L. 600 of 1974 or can be registered with the Central Bank of Chile under the Central Bank Act, Law 18840 of October 1989.

a)	Foreign Investments Contracts and Chapter XXVI

Regarding our initial public offering of ADS in 1993, we entered into a foreign investment contract (the “Foreign Investment Contract”) with the Central Bank of Chile and the Depositary, pursuant to Article 47 of the Central Bank Act and Chapter XXVI of

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the former Compendium of Foreign Exchange Regulations (“Chapter XXVI”), which governed the issuance of ADS by a Chilean company. Pursuant to the Foreign Investment Contract, the foreign exchange for payments and distributions with respect to the ADS may be purchased in either the Formal Exchange Market or the Informal Exchange Market, but such payments must be necessarily remitted through the Formal Exchange Market.

As of April 19, 2001, Chapter XXVI was eliminated and new investments in ADSs by non-residents of Chile are now governed instead by Chapter XIV of the Compendium. This change was made with the purpose of simplifying and facilitating the flow of capital to and from Chile. As a result of the elimination of Chapter XXVI, access to the Formal Exchange Market is no longer assured. However, because our Foreign Investment Contract was entered into pursuant to Chapter XXVI, the principles of Chapter XXVI still apply to its terms. Foreign investors who have purchased their shares under a Foreign Investment Contract pursuant to Chapter XXVI continue to have access to the Formal Exchange Market for the purpose of converting pesos to U.S. dollars and repatriating from Chile amounts received with respect to the deposited shares of common stock or shares of common stock withdrawn from deposit on surrender of ADRs (including amounts received as cash dividends and proceeds from the sale in Chile of the underlying shares of common stock and any rights with respect thereto). However, foreign investors who have not deposited the shares of common stock into our ADS facility will not have the benefits of our Foreign Investment Contract with the Central Bank of Chile but instead will be subject to the normal foreign investment rules.

Effective upon the issuance of new shares in connection with the Capital Increase, all existing shareholders (and ADS holders) will lose the benefits of the Foreign Investment Contracts and Chapter XXVI, including guaranteed access to the Formal Exchange Market. The newly issued securities and the current Common Stock held by non-Chilean residents or domiciles will be subject to Chapter XIV of Central Bank of Chile’s Compendium. The Deposit Agreement will also be amended effective upon the first issuance of shares in connection with the Capital Increase to modify all references to the existing Foreign Investment Contracts to reflect this change.

However, if the Capital Increase is cancelled, there will be no changes to the Foreign Investment Contracts or the Deposit Agreement and the existing arrangements will remain in effect.

The following is a summary of certain provisions which were contained in Chapter XXVI and the Foreign Investment Contract, and which therefore remain relevant. This summary does not purport to be complete and is qualified in its entirety by reference to Chapter XXVI and the Foreign Investment Contract.

Under Chapter XXVI and the Foreign Investment Contract, the Central Bank of Chile agreed to grant to the Depositary, on behalf of ADR holders, and to any investor not residing or domiciled in Chile who withdraws common stock upon delivery of ADRs (such shares of common stock being referred to herein as Withdrawn Shares) access to the Formal Exchange Market to convert pesos into U.S. dollars (and to remit such U.S. dollars outside of Chile), including amounts received as:

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cash dividends;

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proceeds from the sale in Chile of Withdrawn Shares subject to receipt by the Central Bank of Chile of a certificate from the holder of the Withdrawn Shares (or from an institution authorized by the Central Bank of Chile) that such holder’s residence and domicile are outside Chile and a certificate from a Chilean stock exchange (or from a brokerage or securities firm established in Chile) that such Withdrawn Shares were sold on a Chilean stock exchange;

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proceeds from the sale in Chile of rights to subscribe for additional shares of Common Stock;

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proceeds from the liquidation, merger or consolidation of our Company; and

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other distributions, including, without limitation, those resulting from any recapitalization, as a result of holding shares of Common Stock represented by ADS or Withdrawn Shares.

Transferees of Withdrawn Shares were not entitled to any of the foregoing rights under Chapter XXVI. Investors receiving Withdrawn Shares in exchange for ADRs had the right to redeposit such shares in exchange for ADRs, provided that certain conditions relating to redeposit were satisfied.

Chapter XXVI provided that access to the Formal Exchange Market in connection with dividend payments was conditioned upon certification by us to the Central Bank of Chile that a dividend payment has been made and any applicable tax has been withheld. Chapter XXVI also provided that the access to the Formal Exchange Market in connection with the sale of Withdrawn Shares or distributions thereon was conditioned upon receipt by the Central Bank of Chile of certification by the Depositary (or the Custodian on its behalf) that such shares have been withdrawn in exchange for ADRs and receipt of a waiver of the benefit of the Foreign Investment Contract with respect thereto until such Withdrawn Shares were redeposited.

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The Foreign Investment Contract provides that a person who brings foreign currency into Chile to purchase shares of common stock with the benefit of the Foreign Investment Contract must convert it into pesos on the same day and has five banking business days within which to invest in shares of common stock in order to receive the benefits of the Foreign Investment Contract. If such person decides within such period not to acquire shares of common stock, such person can access the Formal Exchange Market to reacquire U.S. dollars, provided that the applicable request is presented to the Central Bank of Chile within seven banking business days of the initial conversion into pesos. Shares acquired as described above may be deposited for ADRs and receive the benefits of the Foreign Investment Contract, subject to receipt by the Central Bank of Chile of a certificate from the Depositary (or the Custodian on its behalf) that such deposit has been effected, that the related ADRs have been issued and receipt of a declaration from the person making such deposit waiving the benefits of the Foreign Investment Contract with respect to the deposited shares of common stock.

Access to the Formal Exchange Market under any of the circumstances described above is not automatic. Such access requires approval of the Central Bank of Chile based on a request presented through a banking institution established in Chile. The Foreign Investment Contract provides that if the Central Bank of Chile has not acted on such request within seven banking days, the request will be deemed approved.

Under current Chilean law, the Foreign Investment Contract cannot be changed unilaterally by the Central Bank of Chile. It is not certain, however, that additional Chilean restrictions applicable to the holders of ADRs, the disposition of underlying shares of Common Stock or the repatriation of the proceeds from such disposition could not be imposed in the future, nor can there be any assessment of the duration or impact of such restrictions, if imposed.

The following is a summary of certain provisions of Chapter XIV that will become applicable to all existing shareholders (and ADS holders) if new shares are issued in connection with the Capital Increase. This summary does not purport to be complete and is qualified in its entirety by reference to Chapter XIV.

Chapter XIV regulates the following type of investments: credits, deposits, investments and equity contributions (such as the contributions to be made to Enersis pursuant to the Capital Increase).

A Chapter XIV investor may at any time repatriate an investment made in Enersis upon sale of the shares of Enersis and the profits derived therefrom, with no monetary ceiling, subject to the then effective regulations, which must be reported to the Central Bank of Chile.

The Compendium and International Bond Issuances

Chilean issuers may offer bonds issued by the Central Bank of Chile internationally under Chapter XIV, as amended, of the Compendium.

E.	Taxation.

Chilean Tax Considerations

The following discussion summarizes material Chilean income and withholding tax consequences to foreign holders arising from the ownership and disposition of ADS rights, rights, shares and ADSs. The summary that follows does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a decision to purchase, own or dispose of ADS rights, rights, shares or ADSs and does not purport to deal with the tax consequences applicable to all categories of investors, some of which may be subject to special rules. Holders of shares and ADSs are advised to consult their own tax advisors concerning the Chilean and other tax consequences of the ownership of shares or ADSs.

The summary that follows is based on Chilean law, as in effect on the date hereof, and is subject to any changes in these or other laws occurring after such date, possibly with retroactive effect. Under Chilean law, provisions contained in statutes such as tax rates applicable to foreign investors, the computation of taxable income for Chilean purposes and the manner in which Chilean taxes are imposed and collected may be amended only by another law. In addition, the Chilean tax authorities enact rulings and regulations of

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either general or specific application and interpret the provisions of the Chilean Income Tax Law. Chilean tax may not be assessed retroactively against taxpayers who act in good faith relying on such rulings, regulations and interpretations, but Chilean tax authorities may change their rulings, regulations and interpretations in the future. The discussion that follows is also based, in part, on representations of the depositary, and assumes that each obligation in the Deposit Agreement and any related agreements will be performed in accordance with its terms. As of this date, there is currently no applicable income tax treaty in effect between the United States and Chile. However, in 2010 the United States and Chile signed an income tax treaty that will enter into force once the treaty is ratified by both countries. There can be no assurance that the treaty will be ratified by either country. The following summary assumes that there is no applicable income tax treaty in effect between the United States and Chile.

As used in this Report, the term “foreign holder” means either:

•

in the case of an individual holder, a person who is not a resident of Chile; for purposes of Chilean taxation, an individual is resident of Chile if he or she has resided in Chile for more than six months in one calendar year, or a total of more than six months in two consecutive fiscal years; or

•

in the case of a legal entity holder, an entity that is not organized under the laws of Chile, unless the shares or ADSs are assigned to a branch, agent, representative or permanent establishment of such entity in Chile.

Taxation of Shares and ADSs

Taxation of Cash Dividends and Property Distributions

General Rule: Cash dividends paid with respect to the shares or ADSs held by a foreign holder will be subject to Chilean withholding tax, which is withheld and paid by the company. As described in the example below, the amount of the Chilean withholding tax is determined by applying a 35% rate to a “grossed-up” distribution amount (such amount equal to the sum of the actual distribution amount and the correlative Chilean corporate income tax paid by the issuer), and then subtracting as a credit such correlative Chilean corporate income tax paid by the issuer. For years 2004 through 2010, the Chilean corporate income tax rate was 17%; for 2011 and hereafter the rate is 20%. The example below illustrates the effective Chilean withholding tax burden on a cash dividend received by a foreign holder, assuming a Chilean withholding tax base rate of 35%, an effective Chilean corporate income tax rate of 20% and a distribution of 50% of the net income of the company distributable after payment of the Chilean corporate income tax:


Line	Concept and calculation assumptions	Amount
1	Company taxable income (based on Line 1 = 100)		100.0
2	Chilean corporate income tax : 20% x Line 1		20.0
3	Net distributable income: Line 1 — Line 2		80.0
4	Dividend distributed (50% of net distributable income): 50% of Line 3		40
5	Withholding tax: (35% of (the sum of Line 4 and 50% of Line 2))		(17.5	)
6	Credit for 50% of Chilean corporate income tax : 50% x Line 2		10
7	Net withholding tax : Line 5 + Line 6		(7.5	)
8	Net dividend received: Line 4 - Line 7		32.5
9	Effective dividend withholding rate : Line 7 / Line 4		18.75	%

In general, the effective Chilean dividend withholding tax rate, after giving effect to the credit for the Chilean corporate income tax paid by the company, can be computed using the following formula:


Effective Dividend	=	(Withholding tax rate) - (Chilean corporate income tax rate)
Withholding Tax Rate	=	1 - (Chilean corporate income tax rate)

Using the prevailing rates, the Effective Dividend Withholding Rate =

(35%-20%) / (100%-20%) = 18.75%

Dividends are generally assumed to have been paid out of the Company’s oldest retained profits for purposes of determining the level of Chilean corporate income tax that was paid by the Company. For information as to the retained earnings of the Company for tax purposes and the tax credit available on the distribution of such retained earnings, see Note 17 to our Consolidated Financial Statements included in this Report.

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Under Chilean Income Tax Law, dividend distributions made in property are subject to the same Chilean tax rules as cash dividends. Stock dividends that represent free shares distributed to foreign shareholders as a consequence of a capitalization made on the same corporation are not subject to Chilean taxation.

Exceptions: Despite the aforementioned general rule, there are special circumstances under which a different tax treatment would apply depending on the source of the income or due to special circumstances existing at the date of the dividend distribution. The most common special cases are briefly described below:

1) Circumstances where there is no corporate income tax credit against the Chilean withholding tax: These cases are when: (i) the financial book profits paid as dividends (following the seniority rule indicated above) exceed the Company’s taxable income (such dividend distributions in excess of the company’s taxable income determined as of December 31 of the distribution’s year will be subject to the Chilean withholding tax rate of 35%, without the corporate income tax credit; in relation to the provisional withholding rule applicable on the date of the dividend payment, please see number 3 below); or (ii) the income was not subject to corporate income tax due to an exemption of the Chilean corporate income tax, in which case the foreign holder will be also subject to the Chilean withholding tax rate of 35% without the corporate income tax credit.

2) Circumstances where dividends have been imputed to income exempted from all the Chilean income taxes: In these cases, dividends distributed by the company to the foreign holder will not be subject to Chilean withholding tax. Income exempted from Chilean income tax is expressly listed in the Chilean Income Tax Law.

3) Circumstances where dividends are subject to a provisional withholding tax: In the event that on the date of the dividend distribution there are no earnings on which income tax has been paid and there are no tax-exempt earnings, a 35% Chilean withholding tax with a provisional 20% Chilean corporate income tax credit is applicable. This provisional 20% Chilean corporate income tax credit granted must be confirmed with the information of Company’s taxable income as of December 31 of the year in which the dividend was paid. The company can agree with the foreign holders to withhold a higher amount in order to avoid under withholding of the Chilean withholding tax.

4) Circumstances when it is possible to use in Chile certain credits against income taxes paid abroad, or “foreign tax credit”: This occurs when dividends distributed by the Chilean company have as their source income generated by companies domiciled in third countries. If that income was subject to withholding tax or corporate income tax in those third countries, such income will have a credit or “foreign tax credit” against corresponding Chilean taxes, which can be proportionally transferred to the shareholders of the Chilean company.

Taxation on sale or exchange of ADSs, outside Chile

Gains obtained by a foreign holder from the sale or exchange of ADSs outside Chile will not be subject to Chilean taxation.

Taxation on sale or exchange of Shares

The Chilean Income Tax Law includes a tax exemption on capital gains arising from the sale of shares of listed companies traded in the stock markets. Although there are certain restrictions, in general terms, the amendment provides that in order to qualify for the capital gain exemption: (i) the shares must be of a publicly held stock corporation with a certain minimum level of trading on a stock exchange; (ii) the sale must be carried out in a Chilean stock exchange, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law; (iii) the shares which are being sold must have been acquired on a Chilean stock exchange, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law, or in an initial public offering (due to the creation of a company or to a capital increase), or due to the exchange of convertible bonds; and (iv) the shares must have been acquired after April 19, 2001.

If the shares do not qualify for the above exemption, capital gains on their sale or exchange of shares (as distinguished from sales or exchanges of ADSs representing such shares of common stock) could be subject to two alternative tax regimes: (a) general tax regime, with a 20% Chilean corporate income tax and a 35% Chilean withholding tax, the former being creditable against the latter; or (b) a 20% Chilean corporate income tax as sole tax regime, when all the following circumstances are met: (i) the sale is made between unrelated parties, (ii) the sale of shares is not a recurrent or habitual activity for the seller and (iii) at least one year has elapsed between the acquisition and the sale of the shares.

The date of acquisition of the ADSs is considered to be the date of acquisition of the shares for which the ADSs are exchanged.

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Taxation of Rights and ADS Rights

For Chilean tax purposes, the receipt of rights or ADS rights by a foreign holder of shares or ADSs pursuant to a rights offering is a nontaxable event. In addition, there are no Chilean income tax consequences to foreign holders upon the exercise or the lapse of the rights or the ADS rights.

Any gain on the sale, exchange or transfer of the ADS rights by a foreign holder is not subject to taxes in Chile.

Any gain on the sale, exchange or transfer of the rights by a foreign holder is subject to a 35% Chilean withholding tax.

Other Chilean Taxes

There is no gift, inheritance or succession tax applicable to the ownership, transfer or disposition of ADSs by foreign holders, but such taxes will generally apply to the transfer at death or by gift of the shares by a foreign holder. There is no Chilean stamp, issue, registration or similar taxes or duties payable by holders of shares or ADSs.

Material U.S. Income Tax Considerations

This discussion is based on the Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions and final, temporary and proposed Treasury regulations, all as of the date hereof. These authorities are subject to change, possibly with retroactive effect. This discussion assumes that the depositary’s activities are clearly and appropriately defined so as to ensure that the tax treatment of ADSs will be identical to the tax treatment of the underlying shares.

The following are the material U.S. federal income tax consequences to U.S. Holders (as defined herein) of receiving, owning and disposing of ADS rights, rights, shares or ADSs, but it does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a particular person’s decision to hold such securities and is based on the assumption stated above under “Chilean Tax Considerations” that there is no applicable income tax treaty in effect between the United States and Chile. The discussion applies only if the beneficial owner holds shares or ADSs as capital assets for U.S. federal income tax purposes and it does not describe all of the tax consequences that may be relevant in light of the beneficial owner’s particular circumstances. For instance, it does not describe all the tax consequences that may be relevant to:

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certain financial institutions;

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insurance companies;

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dealers and traders in securities who use a mark-to-market method of tax accounting;

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persons holding shares or ADSs as part of a “straddle”, integrated transaction or similar transaction;

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persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

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partnerships or other entities classified as partnerships for U.S. federal income tax purposes;

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persons liable for the alternative minimum tax;

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tax-exempt organizations;

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persons holding shares or ADSs that own or are deemed to own ten percent or more of our stock; or

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persons holding shares or ADSs in connection with a trade or business conducted outside of the United States.

If an entity classified as a partnership for U.S. federal income tax purposes holds shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and upon the activities of the partnership. Partnerships holding shares or ADSs and partners in such partnerships should consult their tax advisors as to the particular U.S. federal income tax consequences of holding and disposing of the shares or ADSs.

You are a “U.S. Holder” for purposes of this discussion if you are a beneficial owner of our shares or ADSs and if you are, for U.S. federal income tax purposes:

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a citizen or individual resident of the United States; or

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a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States or any political subdivision thereof; or

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an estate, the income of which is subject to U.S. federal income taxation regardless of its source; or

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•

a trust (i) that validly elects to be treated as a U.S. person for U.S. federal income tax purposes or (ii) if (A) a court within the United States is able to exercise primary supervision over the administration of the trust and (B) one or more U.S. persons have the authority to control all substantial decisions of the trust.

In general, if a beneficial owner owns ADSs, such owner will be treated as the owner of the shares represented by those ADSs for U.S. federal income tax purposes. Accordingly, no gain or loss will be recognized if a beneficial owner exchanges ADSs for the underlying shares represented by those ADSs.

The U.S. Treasury has expressed concerns that parties to whom ADSs are released before shares are delivered to the depositary (pre-release) or intermediaries in the chain of ownership between beneficial owners and the issuer of the security underlying the ADSs may be taking actions that are inconsistent with the claiming of foreign tax credits for beneficial owners of depositary shares. Such actions would also be inconsistent with the claiming of the reduced tax rate, described below, applicable to dividends received by certain non-corporate beneficial owners. Accordingly, the analysis of the creditability of Chilean taxes, and the availability of the reduced tax rate for dividends received by certain non-corporate holders, each described below, could be affected by actions taken by such parties or intermediaries.

This discussion assumes, and the Company believes, that it is not, and will not become, a passive foreign investment company, as described below.

Beneficial owners should consult their tax advisors with respect to their particular tax consequences of owning or disposing of shares or ADSs, including the applicability and effect of state, local, non-U.S. and other tax laws and the possibility of changes in tax laws.

Taxation of Distributions

Distributions paid on shares or ADSs other than certain pro rata distributions of shares of common stock will be treated as dividends taxable as ordinary income to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions generally will be reported as dividends.

If a beneficial owner is a U.S. Holder, subject to applicable limitations and the discussion above regarding concerns expressed by the U.S. Treasury, dividends paid by qualified foreign corporations to the beneficial owner that is not a corporation are taxable at a maximum rate of 20%. A foreign company is treated as a qualified foreign corporation with respect to dividends paid on stock that is readily tradable on an established securities market in the United States, such as the New York Stock Exchange where our ADSs are traded. A beneficial owner should consult its tax advisors to determine whether the favorable rate will apply to dividends it receives and whether it is subject to any special rules that limit its ability to be taxed at this favorable rate.

The amount of a dividend will include the net amount withheld by us in respect of Chilean withholding taxes on the distribution. The amount of the dividend will be treated as foreign-source dividend income to a beneficial owner and will not be eligible for the dividends-received deduction generally allowed to U.S. corporations under the Code. Dividends will be included in a beneficial owner’s income on the date of its, or in the case of ADSs, the Depositary’s, receipt of the dividend. The amount of any dividend paid in Chilean pesos will be a U.S. dollar amount calculated by reference to the exchange rate for converting Chilean pesos into U.S. dollars in effect on the date of such receipt regardless of whether the payment is in fact converted into U.S. dollars. If the dividend is converted into U.S. dollars on the date of receipt, a beneficial owner generally should not be required to recognize foreign currency gain or loss in respect of the dividend income. A beneficial owner may have foreign currency gain or loss if the dividend is converted into U.S. dollars on a date after the date of receipt.

Subject to applicable limitations that may vary depending upon a beneficial owner’s circumstances and subject to the discussion above regarding concerns expressed by the U.S. Treasury, the net amount of Chilean withholding tax (after reduction for the credit for Chilean corporate income tax, as discussed above under “Item 10. Additional Information — E. Taxation — Chilean Tax Considerations — Taxation of Shares and ADSs — Taxation of Cash Dividends and Property Distributions”) withheld from dividends on shares or ADSs will be creditable against a beneficial owner’s U.S. federal income tax liability. The rules governing foreign tax credits are complex and, therefore, a beneficial owner should consult its tax advisor regarding the availability of foreign tax credits in its particular circumstances. Instead of claiming a credit, a beneficial owner may, at its election, deduct such Chilean taxes in computing its taxable income, subject to generally applicable limitations under U.S. law. An election to deduct foreign taxes instead of claiming foreign tax credits applies to all taxes paid or accrued in the taxable year to foreign countries and possessions of the United States.

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Sale or Other Disposition of Shares or ADSs

If a beneficial owner is a U.S. Holder, for U.S. federal income tax purposes, the gain or loss a beneficial owner realizes on the sale or other disposition of shares or ADSs will be a capital gain or loss, and will be a long-term capital gain or loss if the beneficial holder has held the shares or ADSs for more than one year. The amount of a beneficial owner’s gain or loss will equal the difference between the beneficial owner’s tax basis in the shares or ADSs disposed of and the amount realized on the disposition, in each case as determined in U.S. dollars. Such gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. In addition, certain limitations exist on the deductibility of capital losses by both corporate and individual taxpayers.

In certain circumstances, Chilean taxes may be imposed upon the sale of shares. See “Item 10. Additional Information — E. Taxation — Chilean Tax Considerations — Taxation of Shares and ADSs”. If a Chilean tax is imposed on the sale or disposition of shares, and a beneficial owner that is a U.S. Holder does not receive significant foreign source income from other sources, such beneficial owner may not be able to credit such Chilean tax against its U.S. federal income tax liability.

Passive Foreign Investment Company Rules

We believe that we were not a “passive foreign investment company” (“PFIC”) for U.S. federal income tax purposes for our 2012 taxable year and do not expect to be or become one for our 2013 taxable year or for the foreseeable future. However, because PFIC status depends upon the composition of a company’s income and assets and the market value of its assets from time to time, and because it is unclear whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for any taxable year. If we were a PFIC for 2012 or for any prior or future taxable year during which a beneficial owner held shares or ADSs, certain adverse consequences could apply to the beneficial owner, including the imposition of higher amounts of tax than would otherwise apply, and additional filing requirements. A beneficial owner should consult its tax advisors regarding the consequences to it if we were a PFIC, as well as the availability and advisability of making any election that might mitigate the adverse consequences of PFIC status.

Information Reporting and Backup Withholding

Payments of dividends and sales proceeds that are made within the United States or through certain U.S.-related financial intermediaries generally are subject to information reporting and to backup withholding unless (i) the beneficial owner is an exempt recipient or (ii) in the case of backup withholding, the beneficial owner provides a correct taxpayer identification number and certifies that it is not subject to backup withholding.

The amount of any backup withholding from a payment to a beneficial owner will be allowed as a credit against its U.S. federal income tax liability and may entitle it to a refund, provided that the required information is timely furnished to the Internal Revenue Service.

Medicare Contribution Tax

Legislation enacted in 2010 generally imposes a tax of 3.8% on the “net investment income” of certain individuals, trusts and estates. Among other items, net investment income generally includes gross income from dividends and net gain attributable to the disposition of certain property, like the shares, ADSs, less certain deductions. A beneficial owner should consult its tax advisor regarding the possible application of this legislation in its particular circumstances.

A beneficial owner should consult its tax advisors with respect to the particular consequences to it of receiving, owning or disposing of shares or ADSs.

F.	Dividends and Paying Agents.

Not applicable.

G.	Statement by Experts.

Not applicable.

H.	Documents on Display.

We are subject to the information requirements of the Exchange Act, except that as a foreign issuer, we are not subject to the proxy rules (other than general anti-fraud rules) or the short-swing profit disclosure rules of the Exchange Act. In accordance with these statutory requirements, we file or furnish reports and other information with the SEC. Reports and other information filed or furnished by us with the SEC may be inspected and copied at the public reference facilities maintained by the SEC at Room 1024, 100

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F Street, N.E., Washington, D.C. 20549. Copies of such material may also be inspected at the offices of the New York Stock Exchange, 11 Wall Street, New York, New York 10005, on which our ADSs are listed. In addition, the SEC maintains a website that contains information filed electronically with the SEC, which can be accessed over the Internet at http://www.sec.gov.

I.	Subsidiary information.

Not applicable.

Item 11.

Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to risks arising from changes in commodity prices, interest rates and foreign exchange rates. The Company’s Board of Directors approves risk management policies at all levels.

Commodity Price Risk

In our electricity generation business, we are exposed to market risks arising from the price volatility of electricity, natural gas, diesel oil, and coal.

Natural gas is used in some of our power plants in South America. We seek to ensure our supply of this fuel by securing long-term contracts with our suppliers for terms that are expected to match the lifetime of our generation assets. These contracts generally have provisions that allow us to purchase gas at market prices prevailing at the time the purchase occurs. As of December 31, 2012, we hold contracts classified as derivative financial instruments, financial instruments, or derivative commodity instruments related to natural gas.

In the countries where we operate using coal and diesel oil, the dispatch mechanism allows the thermal power plants to cover their variable costs. However, under certain circumstances, fuel price fluctuations might affect marginal costs. We transfer commodity prices variations to the sale contract prices according to indexing formulas but only to the degree that this is possible in our different markets. As of December 31, 2012, we hold contracts classified as derivative financial instruments, financial instruments or derivative commodity instruments related to coal for 365,000 tons and 462,000 barrels of Brent, both deals for the period between January and June 2013.

Additionally, through adequate commercial risk mitigation policies, and a hydro-thermal power plant mix, we seek to naturally protect our operating income from electricity price volatility. As of December 31, 2012, as of the end of the latest fiscal year, we did not hold electricity price-sensitive instruments.

The Company is permanently analyzing ways for hedging commodity price risk. In the future we may use price-sensitive instruments.

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Interest Rate and Foreign Currency Risk

The recorded values of our financial debt as of December 31, 2012, are detailed below, according to maturity. Total values do not include the effect of derivatives.


	Expected Maturity Date
As of December 31,	2013			2014			2015			2016			2017			Thereafter			Total			Fair Value (1)
	(in millions of Ch$)
Fixed Rate
*Ch$ /UF*		0.4			0			0			0			0			0			0.4			0.4
Weighted average interest rate		6.6	%		—			—			—			—			—			6.6	%		—
*US$*		270,603			117,138			103,757			134,381			5,302			184,966			876,146			1,103,329
Weighted average interest rate		8.2	%		7.6	%		8.8	%		7.6	%		8.2	%		7.7	%		8.0	%
*Other currencies (2)*		99,688			72,595			36,498			27,048			27,543			291,860			555,232			579,092
Weighted average interest rate		10.4	%		7.9	%		7.4	%		7.5	%		6.9	%		9.0	%		8.8	%
Total Fixed Rate		370,291			249,733			140,256			161,429			32,845			476,826			1,431,378			1,682,422
Weighted average interest rate		8.8	%		7.7	%		8.4	%		7.6	%		7.1	%		8.5	%		8.3	%

Variable Rate
*Ch$ /UF*		9,721			10,062			10,427			9,280			7,912			298,392			345,793			366,069
Weighted average interest rate		9.2	%		9.2	%		9.2	%		9.0	%		8.7	%		7.6	%		7.8	%
*US$*		24,357			114,486			20,145			19,133			23,842			12,599			214,562			214,562
Weighted average interest rate		5.8	%		2.3	%		3.5	%		3.3	%		3.1	%		4.2	%		3.1	%
*Other currencies (2)*		177,724			164,414			128,450			137,425			248,719			422,293			1,299,024			1,381,468
Weighted average interest rate		11.2	%		10.3	%		9.1	%		9.6	%		9.4	%		8.8	%		9.5	%
Total Variable Rate		211,802			288,961			159,021			165,837			280,472			753,285			1,859,379			1,962,099
Weighted average interest rate		10.5	%		7.1	%		8.4	%		8.8	%		8.8	%		8.2	%		8.5	%

TOTAL		582,093			538,694			229,277			327,266			313,317			1,230,111			3,290,757			3,644,521

(1)	As of December 31, 2012, fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(2)	“Other currencies” include the Euro, reais, Colombian pesos, Argentine pesos and Peruvian soles.

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The recorded values of our financial debt as of December 31, 2011, are detailed below, according to maturity. Total values do not include the effect of derivatives.


	Expected Maturity Date
As of December 31,	2012			2013			2014			2015			2016			Thereafter			Total			Fair Value (1)
	(in millions of Ch$)
Fixed Rate
*Ch$ /UF*		1			0			0			0			0			0			1			1
Weighted average interest rate		6.3	%		—			—			—			—			—			6.3	%		—
*US$*		52,152			225,283			206,136			126,436			154,234			205,823			970,064			1,257,376
Weighted average interest rate		7.0	%		8.8	%		7.7	%		8.9	%		7.6	%		8.0	%		8.1	%
*Other currencies (2)*		93,036			70,681			70,434			34,831			25,146			285,655			579,783			646,471
Weighted average interest rate		11.4	%		8.3	%		8.1	%		7.3	%		7.5	%		9.0	%		9.0	%
Total Fixed Rate		145,189			295,964			276,570			161,266			179,380			491,478			1,549,847			1,903,848
Weighted average interest rate		9.8	%		8.7	%		7.8	%		8.5	%		7.6	%		8.6	%		8.5	%

Variable Rate
*Ch$ /UF*		39,945			9,490			9,823			10,171			9,057			388,148			466,635			618,179
Weighted average interest rate		10.7	%		10.9	%		10.9	%		10.9	%		10.8	%		9.0	%		9.3	%
*US$*		35,455			24,018			122,548			20,494			19,399			38,123			260,037			260,037
Weighted average interest rate		3.9	%		6.8	%		2.3	%		3.4	%		3.0	%		3.3	%		3.2	%
*Other currencies (2)*		349,360			142,042			207,943			122,956			123,382			414,809			1,360,493			1,428,566
Weighted average interest rate		11.1	%		12.8	%		9.9	%		10.3	%		10.5	%		9.8	%		10.6	%
Total Variable Rate		424,760			175,550			340,314			153,622			151,838			841,080			2,087,165			2,306,781
Weighted average interest rate		10.4	%		11.9	%		7.2	%		9.4	%		9.6	%		9.2	%		9.4	%

TOTAL		569,949			471,514			616,883			314,888			331,219			1,332,558			3,637,012			4,210,630

(1)	As of December 31, 2011, fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(2)	“Other currencies” include the Euro, reais, Colombian pesos, Argentine pesos and Peruvian soles.

Interest Rate Risk

At December 31, 2012 and 2011, 38.8% and 38.1% respectively of our outstanding net debt obligations were subject to floating interest rates.

We manage interest rate risk by maintaining a mixture of both variable and fixed rate debt, according to the policy approved by the Board of Directors. Additionally, we manage interest rate risk through the use of interest rate derivatives. The above percentages include the effect of interest rate derivatives (swaps or collars) that hedge part of our debt.

As of December 31, 2012 the recorded values for financial accounting purposes and the corresponding fair values of the instruments that hedge our interest rate risk exposure, are as follows:


	Expected Maturity Date
As of December 31,	2013		2014		2015		2016		2017		Thereafter		Total		Fair Value (2)
	(in millions of Ch$) (1)
Variable to fixed rates		1,728		111,680		4,150		51,907		52,949				222,413		(2,584	)
Fixed to variable rates		-		-		-		-		-		-		-		-
TOTAL		1,728		111,680		4,150		51,907		52,949				222,413		(2,584	)

(1)	Calculated based on the Observed Exchange Rate for December 31, 2012, which was Ch$ 479.96 = US$ 1.00.

(2)	Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

By comparison, as of December 31, 2011, the recorded values for financial accounting purposes and the corresponding fair value of the instruments that hedge for our interest rate risk exposure was as follows:

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	Expected Maturity Date
As of December 31,	2012		2013		2014		2015		2016		Thereafter		Total		Fair Value (2)
	(in millions of Ch$) (1)
Variable to fixed rates		10,781		7,126		125,248		6,894		5,293		8,368		163,709		(4,386	)
Fixed to variable rates		-		-		-		-		-		-		-		-
TOTAL		10,781		7,126		125,248		6,894		5,293		8,368		163,709		(4,386	)

(1)	Calculated based on the Observed Exchange Rate for December 31, 2011, which was Ch$ 519.20 = US$ 1.00.

(2)	Fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

Foreign Currency Risk

We are exposed to foreign currency risk arising from debt denominated in U.S. dollars, Chilean pesos and in other currencies. Some of our subsidiaries have a natural hedge between their revenues and the currency of their debt. For example, in the case of our subsidiaries in Colombia, their revenues are linked to the Colombian peso, as well as their debt. In some other cases, we don’t have this natural hedge and therefore we try to manage this exposure with currency derivatives, such as U.S. dollar/UF exchange and U.S. dollar/local currency derivatives. However, this is not always possible because of market conditions. For example, that is the case of Endesa Costanera in Argentina, that has its revenues linked to the Argentine peso and a substantial part of its debt is denominated U.S. dollars, with no possibility on reasonable conditions to hedge this debt.

Since 2004, we have the current corporate currency risk policy. This policy takes the level of operating income of each country that is indexed to the U.S. dollar and seeks to hedge them with liabilities in the same currency.

As of December 31, 2012, the recorded values for financial accounting purposes and the corresponding fair value of the instruments that hedge our foreign exchange risk are as follows:


	Expected Maturity Date
As of December 31,	2013		2014		2015		2016		2017		Thereafter		Total		Fair Value (2)
	(in millions of Ch$) (1)
UF to $		-		189,894		-		-		-		-		189,894		28,634
$ to Ch$/UF		-		290,498		-		216,342		-		-		506,840		(228,008	)
$ to Other currencies (3)		-		-		4,823		-		-		-		4,823		(3,142	)
Other currencies to $ (4)		-		4,213		-		-		-		-		4,213		578
Total		-		484,605		4,823		216,342		-		-		705,771		(201,938	)

(1)	Calculated based on the Observed Exchange Rate for December 31, 2012, which was Ch$ 479.96 = US$ 1.00.

(2)	Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(3)	Other currencies include the reais.

(4)	Include a Peruvian soles-US$ hedge of Edegel (Chinango).

By comparison, as of December 31, 2011 the recorded values for financial accounting purposes and the corresponding fair values of the instruments that hedge for our interest rate risk was as follows:


	Expected Maturity Date
As of December 31,	2012		2013		2014		2015		2016		Thereafter		Total		Fair Value (2)
	(in millions of Ch$) (1)
UF to US$		-		-		205,419		-		-		-		205,419		9,054
US$ to Ch$/UF		-		-		283,549		-		211,164		-		494,712		(204,519	)
US$ to Other currencies (3)		5,814		1,766		1,892		2,027		-		-		11,499		(7,188	)
Other currencies to US$ (4)		-		-		4,558		-		-		-		4,558		265
Total		5,814		1,766		495,418		2,027		211,164		-		716,188		(202,388	)

(1)	Calculated based on the Observed Exchange Rate for December 31, 2011, which was Ch$ 519.20 =US$ 1.00.

(2)	Fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

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(3)	Other currencies include the reais.

(4)	Include a Peruvian soles-US$ hedge of Edegel (Chinango).

(d)

Safe Harbor

The information in this “Item 11. Quantitative and Qualitative Disclosures About Market Risk,” contains information that may constitute forward-looking statements. See “Forward-Looking Statements” in the Introduction of this Report for safe harbor provisions.

Item 12.

Description of Securities Other Than Equity Securities

A.	Debt Securities.

Not applicable.

B.	Warrants and Rights.

Not applicable.

C.	Other Securities.

Not applicable.

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Item 12. Description of Securities Other Than Equity Securities

D.	American Depositary Shares.

Depositary Fees and Charges

The Company’s ADS program is administered by Citibank, N.A., as Depositary. Under the terms of the Deposit Agreement, an ADS holder may have to pay the following service fees to the Depositary:


Service Fees		Fees
(1) Issuance of ADS upon deposit of Shares		Up to US$ 5.00 per 100 ADS (or fraction thereof) issued.
(2) Delivery of deposited securities against surrender of ADS		Up to US$ 5.00 per 100 ADS (or fraction thereof) surrendered.
(3) Distribution of cash dividends or other cash distributions (i.e., sale of rights and other entitlements)		Up to US$ 5.00 per 100 ADS (or fraction thereof) held.
(4) Distribution of ADS pursuant to (i) stock dividends or other free stock distributions, or (ii) exercise of rights to purchase additional ADS		Up to US$ 5.00 per 100 ADS (or fraction thereof) held.
(5) Distribution of securities other than ADS or rights to purchase additional ADS (i.e., spin—off of shares)		Up to US$ 5.00 per 100 ADS (or fraction thereof) held.
(6) Depositary services		Up to US$ 5.00 per 100 ADS (or fraction thereof) held on the applicable record date(s) established by the Depositary.

Depositary Payments for Fiscal Year 2012

The Depositary has agreed to reimburse certain expenses incurred by the Company in connection with the Company’s ADS program. In 2012, the Depositary reimbursed expenses related to Investor Relations’ activities for a total amount of US$ 449,472 (after applicable US taxes).

PART II

Item 13.

Defaults, Dividend Arrearages and Delinquencies

None.

Item 14.

Material Modifications to the Rights of Security Holders and Use of Proceeds

None.

Item 15.

Controls and Procedures

(a) Disclosure Controls and Procedures

The Company carried out an evaluation under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s “disclosure controls and procedures” (as defined in Rules 13 (a) -15 (e) and 15 (d) -15 (e) under the Exchange Act) for the year ended December 31, 2012.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error, and the circumvention or overriding of the controls and procedures. Accordingly, the Company’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their control objectives.

Based upon the Company’s evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports the

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Company files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the applicable rules and forms, and that it is gathered and communicated to the Company’s Management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives, and our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b) Management’s Annual Report on Internal Control Over Financial Reporting

As required by Section 404 of the Sarbanes—Oxley Act of 2002, Enersis’ management is responsible for establishing and maintaining “adequate internal control over financial reporting” (as defined in Rule 13(a)-15 (f) under the Exchange Act). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS, as issued by the IASB.

Because of its inherent limitations, internal control over financial reporting may not necessarily prevent or detect some misstatements. It can only provide reasonable assurance regarding financial statement preparation and presentation. Also, projections of any evaluation of effectiveness for future periods are subject to the risk that controls may become inadequate because of changes in conditions or because the degree of compliance with the policies or procedures may deteriorate over time.

Management assessed the effectiveness of its internal control over financial reporting for the year ended December 31, 2012. The assessment was based on criteria established in the “Internal Controls — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the assessment, Enersis’ Management has concluded that as of December 31, 2012, the Company’s internal control over financial reporting was effective.

(c) Attestation Report

Ernst & Young Ltda., the independent registered public accounting firm that has audited our Consolidated Financial Statements, has issued an attestation report on the company’s internal control over financial reporting as of December 31, 2012. This attestation report appears on page F-3.

(d) Changes in internal control

There were no changes in the Company’s internal control over financial reporting that occurred during 2012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 16.

[Reserved]

Item 16A.

Audit Committee Financial Expert

As of December 31, 2012, the Directors’ Committee’s (which performs the functions of the Audit Committee) financial expert was Mr. Leonidas Vial, as determined by the Board of Directors. Mr. Vial is an independent member of the Directors’ Committee pursuant to the requirement of both Chilean law and NYSE corporate governance rules.

Item 16B.

Code of Ethics

The standards of ethical conduct at Enersis are currently governed by means of four corporate rulings or policies: the Charter Governing Executives (Estatuto del Directivo), the Code of Ethics, the Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”) and the Manual for the Management of Information of Interest to the Market (the “Manual”).

The Charter Governing Executives, approved as a corporate statute, was adopted by the Board of Directors in May 2003 and is applicable to all executives contractually related to Enersis or its controlled subsidiaries in which it is the majority shareholder, both in Chile and abroad, including the Chief Executive Officer, the Chief Financial Officer and other senior officers of the Company. The objective of this statute is to establish standards for the governance of our management’s actions, the behavior of management with respect to the principles governing their actions and the limitations and incompatibilities involved, all within Enersis’ vision, mission and values. Likewise, the Employee Code of Conduct explains our principles and ethical values, establishes the rules governing our contact with customers and suppliers, and establishes the principles that should be followed by employees, including ethical conduct, professionalism and confidentiality. Both documents also impose limitations on the activities that our executives and other employees may undertake outside the scope of their employment with us.

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The Manual, adopted by Enersis’ Board of Directors in May 2008 and amended in February 2010, addresses the following issues: applicable standards to the transactions of the Company’s securities or those of its affiliates by directors, management, principal executives, employees and other related parties; existence of blackout periods for such transactions by directors, management, principal executives, employees and other related parties; existence of mechanisms for the continuous release of information that is of interest to the market; and mechanisms that provide protection for confidential information.

In addition to the above mentioned corporate governance rules, the Board of the Company approved the Code of Ethics and the ZTAC Plan in its meeting held on June 24, 2010. The Code of Ethics is based on general principles such as impartiality, honesty, integrity and other qualities of similar importance, which are translated into detailed behavioral criteria. The ZTAC Plan reinforces the principles included in the Code of Ethics, but with a special emphasis in avoiding corruption in the form of bribery, preferential treatment, and other similar acts.

A copy of these documents is available upon request, free of charge, by writing or calling us at:

Investor Relations Department

Enersis S.A.

Santa Rosa 76, Piso 15

Santiago, Chile

(56-2) 2353-4682

During fiscal year 2012, there have been no amendments to any provisions of the abovementioned documents. No waivers from any provisions of the Charter Governing Executives, the Code of Ethics, the ZTAC Plan or the Manual, were expressly or implicitly granted to the Chief Executive Officer, the Chief Financial Officer or any other senior financial officer of the Company in fiscal year 2012.

176

Item 16C.

Principal Accountant Fees and Services

The following table provides information on the aggregate billed by our principal accountants, as well as the other members firms of Ernst & Young and their respective affiliates, by type of services rendered for the periods indicated.


Services Rendered	2012		2011
	(in US$ million)
Audit Fees (1)		3.1		2.5
Audit—Related Fees (2)		0.1		—
Tax Fees		—		0.3
All Other Fees (3)		0.2		—

Total		3.4		2.8

(1)	The Audit Fees increase during 2012 was mainly due to the following services provided:

•

Review of Enersis’ interim financial statements and our SEC registrations statement related to the capital increase for US$ 405,116.

•

Interim financial statement review for Endesa Chile’s subsidiaries to support holding investment restructuring for US$ 64,621.

•

Conversion of financial statements in Colombia from local GAAP to IFRS for US$ 104,677.

(2)	The Audit–Related Fees increase was due to a special review of the 2011 financial statements provided to Endesa Brasil, following the electric regulator requirement (ANEEL), for US$ 122,121.

(3)	All Other Fees increased during 2012 mainly due to a project review about research and development and a study regarding energy efficiency provided to Endesa Brasil, for US$ 202,522.

All the services listed above were pre-approved following the Audit Committee Pre-Approval Policies and Procedures.

The amounts included in the table above and the related footnotes have been classified in accordance with SEC guidance.

Audit Committee Pre-Approval Policies and Procedures

Our external auditors are appointed by our shareholders at the OSM. Similarly, the shareholders of our subsidiaries, which are located in countries where applicable law and regulation so establishes, appoint their own external auditors.

The Directors’ Committee (which performs the functions of the Audit Committee), through the Economic Financial General Directorate, or EFGD, manages appointment proposals, reviews engagement letters, fee negotiations, performs quality controls in respect of the services provided, reviews and controls independence issues and other related matters.

The Directors’ Committee has a pre-approval policy regarding the contracting of Enersis’ external auditor, or any affiliate of the external auditor, for professional services. The professional services covered by such policy include audit and non-audit services provided to Enersis.

Fees payable in connection with recurring audit services are pre-approved as part of our annual budget. Fees payable in connection with non-recurring audit services, once they have been analyzed by the EFGD, are submitted to the Audit Committee for approval or rejection.

The pre-approval policy established by the Directors’ Committee for non-audit services and Audit-Related Fees is as follows:

•

The business unit that has requested the service and the audit firm expected to perform the service must request that the EFGD manager review the nature of the service to be provided.

•

At that point, the EFGD analyzes the request and requires the audit firm that will provide the service to issue a certificate signed by the partner responsible for the audit of our Consolidated Financial Statements confirming such audit firm’s independence.

•

Finally, the proposal is submitted to the Audit Committee for approval or denial.

The services described in footnote (2) and (3) to the table above have been approved in line with the procedure described immediately above since July 2005.

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In addition, due to the SEC release number 34-53677 File No. PCAOB-2006-01 (Audit Committee Pre-Approval of Certain Tax Services), the Directors’ Committee has designed, approved and implemented the necessary procedures to fulfill the new requirements described by this rule.

Item 16D.

Exemptions from Listing Requirements for Audit Committees

Not applicable.

Item 16E.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Neither Enersis nor any affiliated purchaser acquired any shares of Enersis during 2012.

Item 16F.

Change in Registrant’s Certifying Accountant

There has been no change in independent accountants for the Company during the two most recent fiscal years or any subsequent interim period except as previously reported in the Company’s Annual Report on Form 20-F for the fiscal year ended December 31, 2010, and there have been no disagreements of the type required to be disclosed by Item 16F (b).

Item 16G.

Corporate Governance

For a summary of the significant differences between our corporate governance practices and those applicable to domestic issuers under the corporate governance rules of the NYSE, please see “Item 6. Directors, Senior Management and Employees — C. Board practices.”

Item 16H.

Mine Safety Disclosure

Not applicable.

178

PART III

Item 17.

Financial Statements

None.

Item 18.

Financial Statements

ENERSIS S.A. and Subsidiaries

Index to the Audited Consolidated Financial Statements


Reports of Independent Registered Public Accounting Firms:
Report of Ernst & Young Servicios Profesionales de Auditoría y Asesorías Limitada — Enersis S.A. 2012 and 2011			F-1
Report of Ernst & Young Servicios Profesionales de Auditoría y Asesorías Limitada — Enersis S.A. — Internal Control over Financial Reporting. 2012			F-3
Report of Deloitte Auditores y Consultores Ltda. — Enersis S.A. 2010			F-5
Report of KPMG Auditores Consultores Ltda. — Empresa Nacional de Electricidad S.A. 2012 and 2011			F-6
Report of KPMG Auditores Consultores Ltda. — Empresa Nacional de Electricidad S.A. — Internal Control over Financial Reporting. 2012			F-8

Consolidated Financial Statements:
Consolidated Statements of Financial Position at December 31, 2012 and 2011			F-10
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010			F-12
Consolidated Statements of Changes in Equity for the years ended December 31, 2012, 2011 and 2010			F-14
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010			F-15
Notes to the Consolidated Financial Statements			F-17

SCHEDULE I Enersis S.A.’s condensed unconsolidated financial information			F-145

Item 19.

Exhibits


Exhibit		Description
1.1		By-laws (Estatutos) of ENERSIS S.A., as amended.(*)
8.1		List of Subsidiaries as of December 31, 2012
12.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes—Oxley Act
12.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes—Oxley Act
13.1		Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes—Oxley Act
23.1		Consent of Ernst & Young Servicios Profesionales de Auditoría y Asesorías, an independent registered public accounting firm
23.2		Consent of Deloitte Auditores y Consultores Ltda., an independent registered public accounting firm
23.3		Consent of KPMG Auditores Consultores Ltda., an independent registered public accounting firm

(*)	Incorporated by reference from Exhibit 1.1 to Enersis’ Registration Statements on Form F-3 (Registration No. 333-186823)

We will furnish to the Securities and Exchange Commission, upon request, copies of any not filed instruments that define the rights of stakeholders of Enersis.

179

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.


ENERSIS S.A.

By:		/s/ Ignacio Antoñanzas A.
		Name: Ignacio Antoñanzas A.
		Title: Chief Executive Officer

Date: March 20, 2013.

180

Enersis and Subsidiaries

Audited Consolidated Financial Statements as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012 together with the Reports of Independent Registered Public Accounting Firms

Enersis S.A. and Subsidiaries

Index to the Audited Consolidated Financial Statements


Reports of Independent Registered Public Accounting Firms:
Report of Ernst & Young Servicios Profesionales de Auditoría y Asesorías Limitada — Enersis S.A. 2012 and 2011			F-1
Report of Ernst & Young Servicios Profesionales de Auditoría y Asesorías Limitada — Enersis S.A. — Internal Control over Financial Reporting. 2012			F-3
Report of Deloitte Auditores y Consultores Ltda. — Enersis S.A. 2010			F-5
Report of KPMG Auditores Consultores Ltda. — Empresa Nacional de Electricidad S.A. 2012 and 2011			F-6
Report of KPMG Auditores Consultores Ltda. — Empresa Nacional de Electricidad S.A. — Internal Control over Financial Reporting. 2012			F-8

Consolidated Financial Statements:
Consolidated Statements of Financial Position at December 31, 2012 and 2011			F-10
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010			F-12
Consolidated Statements of Changes in Equity for the years ended December 31, 2012, 2011 and 2010			F-14
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010			F-15
Notes to the Consolidated Financial Statements			F-17

SCHEDULE I Enersis S.A.’s condensed unconsolidated financial information			F-145


Ch$		Chilean pesos
US$		U.S. dollars
UF		The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is set daily in advance based on the previous month’s inflation rate.
ThCh$		Thousand of Chilean pesos
ThUS$		Thousand of U.S. dollars

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Enersis S.A.

We have audited the accompanying consolidated statements of financial position of Enersis S.A. and subsidiaries (“the Company”) as of December 31, 2012 and 2011, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for each of the two years in the period ended December 31, 2012 and the schedule of Enersis S.A.’s condensed unconsolidated financial information. These consolidated financial statements and the schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the schedule based on our audits.

The consolidated financial statements of the Company include the consolidated financial statements of its subsidiary, Empresa Nacional de Electridad S.A (“Endesa-Chile”). The consolidated financial statements of Endesa-Chile include the financial statements of the following entities, each having been prepared in conformity with its respective local statutory accounting basis: Emgesa S.A. E.S.P (“Emgesa”) and Endesa Argentina S.A. (“Endesa-Argentina”) (both subsidiaries of Endesa-Chile), and of Endesa Brasil S.A. (“Endesa-Brasil”) (a consolidated subsidiary of the Company that is also a 40.45% percent owned investee of Endesa-Chile accounted for using the equity method). Except for the amounts included in Endesa-Chile’s consolidated financial statements relating to Emgesa, Endesa-Argentina and Endesa-Brasil, which we subjected to our audit procedures in the context of the financial statements of Enersis, taken as a whole, we did not audit the consolidated financial statements of Endesa-Chile. The consolidated financial statements of Endesa-Chile, exclusive of the amounts relating to Emgesa, Endesa-Argentina and Endesa-Brasil, reflect total assets constituting 28% and 29% of the Company’s consolidated total assets as of December 31, 2012 and 2011, respectively, and total revenues constituting 18% and 16% of the Company’s consolidated total revenues for the years ended December 31, 2012 and 2011, respectively. Endesa-Chile’s consolidated financial statements were audited by other auditors whose report has been furnished to us, and our opinion on the Company’s consolidated financial statements, insofar as it relates to the amounts included for Endesa-Chile (but exclusive of the amounts for Emgesa, Endesa-Argentina and Endesa-Brasil), is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

F-1

In our opinion, based on our audits and the report of other auditors (see second paragraph above), the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Enersis S.A. and subsidiaries at December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2012, in conformity with International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (“IASB”). Also, in our opinion, the related schedule of condensed unconsolidated financial information, when considered in relation to the basic consolidated financial statements, taken as whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Enersis S.A.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 20, 2013 expressed an unqualified opinion thereon based on our audit and the report on internal controls of other auditors

/s/ Ernst & Young Ltda.

Santiago, Chile

March 20, 2013

F-2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Enersis S.A.

We have audited the internal control over financial reporting of Enersis S.A. and subsidiaries (“the Company”) as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We did not examine the effectiveness of internal control over financial reporting of Empresa Nacional De Electricidad S.A. (a subsidiary) and certain of its subsidiaries, associates and jointly controlled entities (hereinafter collectively referred to as “Endesa-Chile”) which statements reflect total assets constituting 44 % in 2012, and total revenues constituting 29 % in 2012 of the related consolidated totals. The effectiveness of Endesa-Chile’s internal control over financial reporting was audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the effectiveness of Endesa-Chile’s internal control over financial reporting, is based solely on the report of the other auditors.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

F-3

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, based on our audit and the report of other auditors, Enersis S.A. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), consolidated statements of financial position of Enersis S.A. and subsidiaries (“the Company”) as of December 31, 2012 and 2011, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for each of the two years in the period ended December 31, 2012 and the schedule of Enersis S.A.’s condensed unconsolidated financial information and our report dated March 20, 2013 expressed an unqualified opinion thereon based on our audit and the report of other auditors.

/s/ Ernst & Young Ltda.

Santiago, Chile

March 20, 2013

F-4

LOGO

Deloitte Auditores y Consultores Ltda.

RUT: 80.276.200-3

Rosario Norte 407

Las Condes, Santiago

Chile

Fono: (56-2) 2729 7000

Fax: (56-2) 2374 9177

e-mail: deloittechile@deloitte.com

www.deloitte.cl

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Enersis S.A.

We have audited the accompanying consolidated statements of comprehensive income, changes in equity, and cash flows of Enersis S.A. and subsidiaries (“the Company” or “Enersis”) for the year ended December 31, 2010, and the schedule of Enersis S.A.’s condensed unconsolidated financial information for the year ended December 31, 2010. These consolidated financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the schedules based on our audit.

The consolidated financial statements of the Company include the financial statements of its consolidated subsidiary, Empresa Nacional de Electricidad S.A (“Endesa-Chile”). The consolidated financial statements of Endesa-Chile include the financial statements of the following entities, each having been prepared in conformity with its respective local statutory accounting basis: Emgesa S.A. E.S.P. (“Emgesa-Colombia”) (a consolidated subsidiary), and Endesa Brasil S.A. (“Endesa-Brasil”) (a consolidated subsidiary of the Company that is also a 40.45 percent owned investee of Endesa-Chile accounted for using the equity method). Except for the amounts included in Endesa-Chile’s consolidated financial statements relating to Emgesa-Colombia and Endesa-Brasil, which we subjected to our audit procedures in the context of the financial statements of Enersis, taken as a whole, we did not audit the consolidated financial statements of Endesa-Chile. The consolidated financial statements of Endesa-Chile, exclusive of the amounts relating to Emgesa-Colombia and Endesa-Brasil, which were subjected to our audit procedures in the context of the financial statements of Enersis, taken as a whole, reflect total assets constituting 35.01% of the Company’s consolidated total assets as of December 31, 2010, and total revenues constituting 27.31% of the Company’s consolidated total revenues for the year ended December 31, 2010. Endesa-Chile’s consolidated financial statements were audited by other auditors whose report has been furnished to us, and our opinion on the Company’s consolidated financial statements, insofar as it relates to the amounts included for Endesa-Chile (but exclusive of the amounts for Emgesa-Colombia and Endesa-Brasil, which were prepared in conformity with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”) and were subjected to our audit procedures in the context of the financial statements of Enersis, taken as a whole), is based solely on the report of the other auditors.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit and the report of other auditors (see second paragraph of this report) provide a reasonable basis for our opinion.

In our opinion, based on our audit and the report of other auditors (see second paragraph of this report), the Company´s consolidated financial statements of Enersis S.A. and subsidiaries referred to above present fairly, in all material respects, the consolidated results of their operations and their cash flows for the year ended December 31, 2010, in conformity with IFRS, as issued by the IASB. Also, in our opinion, the related schedules of condensed unconsolidated financial information for the year ended December 31, 2010, when considered in relation to the basic consolidated financial statements, taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte

Santiago, Chile

February 24, 2013

F-5

KPMG Auditores Consultores Ltda.

Av. Isidora Goyenechea 3520, Piso 2

Las Condes, Santiago, Chile

Teléfono +56 (2) 2798 1000

Fax +56 (2) 2798 1001

www.kpmg.cl

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Empresa Nacional de Electricidad S.A. (Endesa–Chile):

We have audited the accompanying consolidated statements of financial position of Endesa-Chile and subsidiaries (the Company) as of December 31, 2012 and 2011, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of certain subsidiaries, which statements reflect total assets constituting 33.36 percent and 30.05 percent of the Company’s consolidated total asset position as of December 31, 2012 and 2011, respectively, and total revenues constituting 37.36 percent, 35.29 percent and 20.04 percent of the Company’s consolidated revenues for the years ended December 31, 2012, 2011 and 2010, respectively. In addition, we did not audit the financial statements of Endesa Brasil S.A. (a 40.45% percent owner investee Company). The Company’s investment in Brazil at December 31, 2012 and 2011 was M$ 574,168,681 and M$569,012,759 as of December 31, 2012 and 2011, respectively, and its equity earning was M$107,503,620, M$115,355,267 and M$90,667,296 for the years ended December 31, 2012, 2011 and 2010, respectively. Those consolidated financial statements prepared in accordance with the local statutory accounting basis were audited by other auditors whose reports have been furnished to us and our opinion, insofar as it relates to the amounts included for those entities on such basis of accounting, is based solely on the reports of the other auditors. Accordingly, we have audited the conversion adjustments to the financial statements of these subsidiaries and nonsubsidiary investees prepared in accordance with the local statutory accounting basis to conform them to the Company’s accounting basis referred to below.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion.

F-6

In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Endesa-Chile and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Endesa-Chile’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 20, 2013, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG

KPMG Auditores Consultores Ltda.

Santiago, Chile

March 20, 2013

^© 2013 KPMG Auditores Consultores Ltda, a Chilean limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.

F-7

KPMG Auditores Consultores Ltda.

Av. Isidora Goyenechea 3520, Piso 2

Las Condes, Santiago, Chile

Teléfono +56 (2) 2798 1000

Fax +56 (2) 2798 1001

www.kpmg.cl

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Empresa Nacional de Electricidad S.A. (Endesa–Chile):

We have audited Endesa-Chile’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Endesa-Chile’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Endesa-Chile’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

F-8

In our opinion, Endesa-Chile maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated statement of financial position of Endesa-Chile and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of comprehensive income, changes in stockholder’s equity, and cash flows for each of years in the three-year period ended December 31, 2012, and our report dated March 20, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG

KPMG Auditores Consultores Ltda.

Santiago, Chile

March 20, 2013

F-9

ENERSIS S.A. AND SUBSIDIARIES

Consolidated Statements of Financial Position, Classified

at December 31, 2012 and 2011

(In thousands of Chilean pesos)


ASSETS	Note	12-31-2012	12-31-2011
ASSETS	Note	ThCh$	ThCh$

CURRENT ASSETS

Cash and cash equivalents	5	857,380,018	1,219,921,268
Other current financial assets	6	194,500,798	939,220
Other current non-financial assets		105,919,767	72,466,312
Trade and other current receivables	7	869,204,566	977,602,388
Accounts receivable from related companies	8	33,028,911	35,282,592
Inventories	9	83,479,493	77,925,544
Current tax assets	10	211,004,880	141,827,684
Total current assets other than assets classified as held for sale and discontinued operations		2,354,518,433	2,525,965,008


Non-current assets classified as held for sale and discontinued operations	11	-	-
Non-current assets classified as held for sale and discontinued operations		-	-


TOTAL CURRENT ASSETS		2,354,518,433	2,525,965,008

NON-CURRENT ASSETS


Other non-current financial assets	6	439,115,917	37,355,061
Other non-current non-financial assets		87,822,131	109,501,108
Non-current receivables	7	202,977,693	443,328,450
Investments accounted for using the equity method	12	12,176,684	13,193,262
Intangible assets other than goodwill	13	1,203,135,574	1,467,398,214
Goodwill	14	1,399,876,589	1,476,404,126
Property, plant, and equipment, net	15	7,243,620,209	7,242,731,006
Investment property	16	46,922,970	38,055,889
Deferred tax assets	17	327,667,440	379,938,628


TOTAL NON-CURRENT ASSETS		10,963,315,207	11,207,905,744


TOTAL ASSETS		13,317,833,640	13,733,870,752

F-10

ENERSIS S.A. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income, by Type

for the years ending December 31, 2012, and 2011

(In thousands of Chilean pesos)


LIABILITIES AND EQUITY	Note	12-31-2012	12-31-2011
LIABILITIES AND EQUITY	Note	ThCh$	ThCh$

CURRENT LIABILITIES

Other current financial liabilities	18	670,182,208	672,082,338
Trade and other current payables	21	1,213,259,735	1,235,064,459
Accounts payable to related companies	8	146,827,411	157,177,638
Other current provisions	22	91,130,695	99,702,654
Current tax liabilities	10	173,136,710	235,853,242
Other current non-financial liabilities		86,575,476	60,653,304

Total current liabilities other than those associated with current assets classified as held for sale and discontinued operations		2,381,112,235	2,460,533,635

Liabilities associated with current assets classified as held for sale and discontinued operations	11	-	-

TOTAL CURRENT LIABILITIES		2,381,112,235	2,460,533,635

NON-CURRENT LIABILITIES

Other non-current financial liabilities	18	2,928,119,869	3,271,355,293
Other non-current payables	21	14,257,438	14,304,607
Non-current accounts payable to related companies	8	-	-
Other long-term provisions	22	177,078,989	202,573,641
Deferred tax liabilities	17	519,026,046	508,438,255
Non-current provisions for employee benefits	23	265,067,889	277,526,013
Other non-current non-financial liabilities		69,402,596	102,985,451

TOTAL NON-CURRENT LIABILITIES		3,972,952,827	4,377,183,260

TOTAL LIABILITIES		6,354,065,062	6,837,716,895


EQUITY
Issued capital	24.1	2,824,882,835	2,824,882,835
Retained earnings		2,421,278,841	2,232,968,880
Share premium	24.1	158,759,648	158,759,648
Other reserves	24.5	(1,511,122,753)	(1,320,882,757)
Equity attributable to shareholders of Enersis		3,893,798,571	3,895,728,606

Non-controlling interests	24.6	3,069,970,007	3,000,425,251

TOTAL EQUITY		6,963,768,578	6,896,153,857

TOTAL LIABILITIES AND EQUITY		13,317,833,640	13,733,870,752

F-11

ENERSIS S.A. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income, by Type

for the years ending December 31, 2012, 2011 and 2010

(In thousands of Chilean pesos)


		January - December
STATEMENT OF COMPREHENSIVE INCOME	Note	2012 ThCh$			2011 ThCh$			2010 ThCh$
Sales	25		6,260,309,229			6,254,252,089			6,179,229,824
Other operating income	25		317,358,085			280,628,255			384,351,289
Revenues			6,577,667,314			6,534,880,344			6,563,581,113

Raw materials and consumables used	26		(3,717,125,487	)		(3,538,434,729	)		(3,521,646,254	)
Contribution Margin			2,860,541,827			2,996,445,615			3,041,934,859
Contribution Margin

Other work performed by the entity and capitalized			48,853,687			50,173,112			44,869,365
Employee benefits expenses	27		(416,345,140	)		(378,552,126	)		(374,678,013	)
Depreciation and amortization expense	28		(442,854,723	)		(424,900,036	)		(449,017,275	)
Reversal of impairment loss (impairment loss) recognized in the year’s profit or loss	28		(43,105,193	)		(136,157,459	)		(108,373,429	)
Other expenses	29		(510,125,910	)		(540,698,397	)		(450,434,769	)
Operating Income			1,496,964,548			1,566,310,709			1,704,300,738
Operating Income

Other gains (losses)	30		14,831,474			(4,814,294	)		11,983,434
Financial income	31		264,709,235			233,612,869			171,236,948
Financial costs	31		(453,447,437	)		(465,411,363	)		(438,358,251	)
Share of profit (loss) of associates accounted for using the equity method	12		9,845,902			8,465,904			1,015,739
Foreign currency exchange differences	31		(14,768,878	)		20,305,690			11,572,474
Profit (loss) from indexed assets and liabilities	31		(12,681,628	)		(25,092,203	)		(15,055,706	)

Net income before tax			1,305,453,216			1,333,377,312			1,446,695,376
Income tax	32		(411,891,234	)		(460,836,692	)		(346,006,968	)
Net income from continuing operations			893,561,982			872,540,620			1,100,688,408
Net income from discontinued operations			-			-			-
NET INCOME			893,561,982			872,540,620			1,100,688,408
Net income attributable to:
Shareholders of Enersis			377,350,521			375,471,254			486,226,814
Non-controlling interests			516,211,461			497,069,366			614,461,594
NET INCOME			893,561,982			872,540,620			1,100,688,408
Basic earnings per share
Basic earnings per share from continuing operations	Ch$ / Share		11.56			11.50			14.89
Basic earnings per share	Ch$ / share		11.56			11.50			14.89
Diluted earnings per share
Diluted earnings per share from continuing operations	Ch$ / share		11.56			11.50			14.89
Diluted earnings per share	Ch$ / share		11.56			11.50			14.89

F-12

ENERSIS S.A. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income, by Type

for the years ending December 31, 2012, 2011 and 2010

(In thousands of Chilean pesos)


		January–December
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME	Note	2012 ThCh$			2011 ThCh$			2010 ThCh$

Net Income			893,561,982			872,540,620		1,100,688,408

Components of other comprehensive income, before taxes
Exchange differences on translation

Foreign currency translation gains (losses), before taxes			(363,936,877	)		211,929,739		(138,554,045)
Total exchange differences on translation			(363,936,877	)		211,929,739		(138,554,045)

Available-for-sale financial assets
Gains (losses) from new measuring of available-for-sale financial assets, before taxes			515			(55,959	)	(179)
Total available-for-sale financial assets			515			(55,959	)	(179)

Cash flow hedge

Gains (losses) from cash flow hedge, before taxes			73,142,760			(79,722,581	)	50,576,145
Reclassification adjustments on cash flow hedge, before taxes			(6,300,885	)		(8,309,911	)	(19,664,842)
Total cash flow hedge			66,841,875			(88,032,492	)	30,911,303


Actuarial gains (losses) on defined benefit plans			(15,001,248	)		(62,246,623	)	(48,495,375)

Total other components of other comprehensive income, before taxes			312,095,735			61,594,665		(156,138,296)

Income tax related to components of other comprehensive income
Income tax related to available-for-sale financial assets			(569	)		9,513		31
Income tax related to cash flow hedge			(25,726,629	)		14,110,400		(5,301,050)
Income tax related to defined benefit plans			4,662,040			23,078,884		16,515,279
Total income tax			(21,065,158	)		37,198,797		11,214,260

Total Other Comprehensive Income			(333,160,893	)		98,793,462		(144,924,036)
TOTAL COMPREHENSIVE INCOME			560,401,089			971,334,082		955,764,372

Comprehensive income attributable to
Shareholders of Enersis			187,169,558			368,568,685		396,687,094
Non-controlling interests			373,231,531			602,765,397		559,077,278
TOTAL COMPREHENSIVE INCOME			560,401,089			971,334,082		955,764,372

F-13

ENERSIS S.A. AND SUBSIDIARIES

Statements of Changes in Equity

for the years ending December 31, 2012, 2011, and 2010

(In thousands of Chilean pesos)


					Changes in Other Reserves
Statement of Changes in Net Equity	Issued Capital		Share Premium		Reserve for Exchange Differences in Translation		Reserve for Cash Flow Hedge		Reserve for Gains and Losses for Defined Benefit Plans		Reserve for Gains and Losses on Remeasuring Available-for- sale Financial Assets		Other Miscellaneous Reserves		Other Reserves		Retained Earnings		Equity Attributable to Shareholders of Enersis		Non-controlling Interests		Total Equity
Equity at beginning of year 1/1/2012		2,824,882,835		158,759,648		176,622,668		(310,265)		-		13,836		(1,497,208,996)		(1,320,882,757)		2,232,968,880		3,895,728,606		3,000,425,251		6,896,153,857
Changes in equity
Comprehensive income
Net income																		377,350,521		377,350,521		516,211,461		893,561,982
Other comprehensive income						(217,342,727)		27,904,293		(742,368)		(189)		28		(190,180,963)				(190,180,963)		(142,979,930)		(333,160,893)
Comprehensive income																				187,169,558		373,231,531		560,401,089
Dividends																		(188,298,192)		(188,298,192)				(188,298,192)
Increase (decrease) through transfers and other changes						-				742,368				(801,401)		(59,033)		(742,368)		(801,401)		(303,686,775)		(304,488,176)
Total changes in equity		-		-		(217,342,727)		27,904,293		-		(189)		(801,373)		(190,239,996)		188,309,961		(1,930,035)		69,544,756		67,614,721
Equity at end of year 12/31/2012		2,824,882,835		158,759,648		(40,720,059)		27,594,028		-		13,647		(1,498,010,369)		(1,511,122,753)		2,421,278,841		3,893,798,571		3,069,970,007		6,963,768,578


Equity at beginning of year 1/1/2011		2,824,882,835		158,759,648		113,278,890		40,783,463		-		41,825		(1,505,891,534)		(1,351,787,356)		2,103,689,509		3,735,544,636		2,778,483,320		6,514,027,956
Changes in equity
Comprehensive income
Net income																		375,471,254		375,471,254		497,069,366		872,540,620
Other comprehensive income						60,106,895		(41,093,728)		(25,887,747)		(27,989)		-		(6,902,569)				(6,902,569)		105,696,031		98,793,462
Comprehensive income																				368,568,685		602,765,397		971,334,082
Dividends																		(209,886,734)		(209,886,734)				(209,886,734)
Increase (decrease) through transfers and other changes						3,236,883				25,887,747				8,682,538		37,807,168		(36,305,149)		1,502,019		(380,823,466)		(379,321,447)
Total changes in equity		-		-		63,343,778		(41,093,728)		-		(27,989)		8,682,538		30,904,599		129,279,371		160,183,970		221,941,931		382,125,901
Equity at end of year 12/31/2011		2,824,882,835		158,759,648		176,622,668		(310,265)		-		13,836		(1,497,208,996)		(1,320,882,757)		2,232,968,880		3,895,728,606		3,000,425,251		6,896,153,857


Equity at beginning of year 1/1/2010		2,824,882,835		158,759,648		196,973,210		26,100,491		-		41,699		(1,505,891,534)		(1,282,776,134)		1,817,613,206		3,518,479,555		2,858,524,089		6,377,003,644
Changes in equity
Comprehensive income
Net income																		486,226,814		486,226,814		614,461,594		1,100,688,408
Other comprehensive income						(83,694,320)		14,682,972		(20,528,498)		126		-		(89,539,720)				(89,539,720)		(55,384,316)		(144,924,036)
Comprehensive income																				396,687,094		559,077,278		955,764,372
Dividends																		(179,622,013)		(179,622,013)				(179,622,013)
Increase (decrease) through transfers and other changes		-		-		-		-		20,528,498		-		-		20,528,498		(20,528,498)		-		(639,118,047)		(639,118,047)
Total changes in equity		-		-		(83,694,320)		14,682,972		-		126		-		(69,011,222)		286,076,303		217,065,081		(80,040,769)		137,024,312
Equity at end of year 12/31/2010		2,824,882,835		158,759,648		113,278,890		40,783,463		-		41,825		(1,505,891,534)		(1,351,787,356)		2,103,689,509		3,735,544,636		2,778,483,320		6,514,027,956

F-14

ENERSIS S.A. AND SUBSIDIARIES

Consolidated Statements of Direct Cash Flow

for the years ending December 31, 2012, 2011, and 2010

(In thousands of Chilean pesos)


		January - December
Statement of Direct Cash Flow	Note	2012 ThCh$		2011 ThCh$		2010 ThCh$
Cash flows from (used in) operating activities

Types of collections from operating activities
Collections from the sale of goods and services			7,496,002,995		7,725,639,255		7,343,782,195
Collections from royalties, payments, commissions, and other income from ordinary activities			92,758,277		86,290,041		87,055,879
Other collections from operating activities			391,974,798		256,467,291		223,147,303
Types of payments
Payments to suppliers for goods and services			(3,934,574,455)		(3,942,239,405)		(3,687,515,697)
Payments to and on behalf of employees			(409,539,542)		(358,459,354)		(292,233,107)
Payments on premiums and services, annual payments, and other obligations from policies held			(9,397,983)		(5,742,211)		(2,533,860)
Other payments for operating activities			(1,352,330,115)		(1,545,840,676)		(1,142,818,147)
Income tax reimbursed (paid)			(457,738,318)		(361,092,038)		(349,296,688)
Other inflows (outflows) of cash			(256,517,095)		(156,576,437)		(236,172,731)

Net cash flows from (used in ) operating activities			1,560,638,562		1,698,446,466		1,943,415,147

Cash flows from (used in) investment activities
Cash flows from losing control of subsidiaries or other business			-		12,662,234		-
Loans to related companies			-		(25,500)		-
Proceeds from the sale of property, plant and equipment			918,437		6,048,912		8,889,879
Purchase of property, plant and equipment			(527,630,629)		(495,958,729)		(473,727,882)
Proceeds from the sales of intangible assets			-		8,965,592		1,424,691
Purchases of intangible assets			(187,490,636)		(187,864,119)		(227,418,842)
Proceeds from other long-term assets			305,552		41,114		-
Purchases of other long-term assets			(2,859,668)		(2,183,333)		(193,947)
Dividends received			7,539,711		4,025,233		3,278,931
Interest received			56,687,582		19,611,804		6,807,678
Other inflows (outflows) of cash			(195,751,318)		10,707,112		(94,841,624)

Net cash flows from (used in) investment activities			(848,280,969)		(623,969,680)		(775,781,116)

F-15

ENERSIS S.A. AND SUBSIDIARIES

Consolidated Statements of Direct Cash Flow

for the years ending December 31, 2012, 2011, and 2010

(In thousands of Chilean pesos)


			January - December
Statement of Direct Cash Flow	Note		2012 ThCh$		2011 ThCh$		2010 ThCh$

Cash flows from (used in) financing activities
Total proceeds from loans				508,817,790		646,273,100		263,124,754
Proceeds from long-term loans				400,797,521		525,077,859		218,392,462
Proceeds from short-term loans				108,020,269		121,195,241		44,732,292
Loans from related companies				-		9,128,650		821,636
Repayments from borrowings				(651,209,149)		(629,404,409)		(740,286,720)
Payments of finance lease liabilities				(25,491,730)		(11,478,851)		(24,129,963)
Dividends paid				(547,081,888)		(648,107,205)		(556,087,040)
Interest paid				(254,327,622)		(248,096,873)		(244,595,847)
Other inflows (outflows) of cash				(42,791,188)		(9,743,963)		18,132,411
Net cash flows from (used in) financing activities				(1,012,083,787)		(891,429,551)		(1,283,020,769)

Net increase (decrease) in cash and cash equivalents before effect of exchange rate changes				(299,726,194)		183,047,235		(115,386,738)

Effect of exchange rate changes on cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents				(62,815,056)		75,518,996		(58,159,046)
Net increase (decrease) in cash and cash equivalents				(362,541,250)		258,566,231		(173,545,784)
Cash and cash equivalents at beginning of year		5		1,219,921,268		961,355,037		1,134,900,821
Cash and cash equivalents at end of year		5		857,380,018		1,219,921,268		961,355,037

F-16

ENERSIS S.A. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


Contents			F Page

1.	THE GROUP’S ACTIVITIES AND FINANCIAL STATEMENTS		20

2.	BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS		20
	2.1.	Accounting principles	20
	2.2.	New accounting pronouncements	21
	2.3.	Responsibility for the information and estimates made	24
	2.4.	Subsidiaries and joint ventures	25
		2.4.1. Changes in the scope of consolidation	25
		2.4.2. Consolidated companies with an ownership interest of less than 50%	25
		2.4.3. Non-consolidated companies with an ownership interest of over 50%	25
	2.5.	Associated companies	25
	2.6.	Basis of consolidation and business combinations	26

3.	ACCOUNTING PRINCIPLES APPLIED		26
	a)	Property, plant, and equipment	26
	b)	Investment property	28
	c)	Goodwill	28
	d)	Intangible assets other than goodwill	29
	e)	Assets Impairment	30
	f)	Leases	31
	g)	Financial instruments	31
	h)	Investments accounted for using the equity method	34
	i)	Inventories	34
	j)	Non-current assets held for sale and discontinued operations	34
	k)	Treasury shares	35
	l)	Provisions	35
	m)	Conversion of balances in foreign currency	35
	n)	Current / non-current classification	36
	o)	Income tax	36
	p)	Revenue and expense recognition	36
	q)	Earnings per share	37
	r)	Dividends	37
	s)	Systems of share-based remunerations	37
	t)	Cash flow statement	37

4.	SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS		37
	4.1.	Generation	37
	4.2.	Distribution	40

5.	CASH AND CASH EQUIVALENTS		42

6.	OTHER FINANCIAL ASSETS		43

7.	TRADE AND OTHER RECEIVABLES		43

8.	BALANCES AND TRANSACTIONS WITH RELATED PARTIES		45
	8.1	Balances and transactions with related companies	45
	8.2	Board of Directors and key management personnel	48
	8.3	Compensation for key management personnel	50
	8.4	Compensation plans linked to share price	43

F-17


9.	INVENTORIES		44

10.	TAX RECEIVABLES AND PAYABLES		44

11.	NON-CURRENT ASSETS AND DISPOSAL GROUPS HELD FOR SALE		45

12.	INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD AND JOINT VENTURES		46

	12.1.	Investments accounted for using the equity method	46

	12.2.	Joint ventures	47

13.	INTANGIBLE ASSETS OTHER THAN GOODWILL		48

14.	GOODWILL		49

15.	PROPERTY, PLANT AND EQUIPMENT		51

16.	INVESTMENT PROPERTY		54

17.	DEFERRED TAX		55

18.	OTHER FINANCIAL LIABILITIES		56
	18.1.	Interest-bearing borrowings	57
	18.2.	Unsecured Liabilities	60
	18.3.	Secured Liabilities	60
	18.4.	Hedged debt	65
	18.5.	Other information	65

19.	RISK MANAGEMENT POLICY		65
	19.1.	Interest rate risk	66
	19.2.	Exchange rate risk	66
	19.3.	Commodities risk	66
	19.4.	Liquidity risk	67
	19.5.	Credit risk	67
	19.6.	Risk measurement	68

20.	FINANCIAL INSTRUMENTS		69
	20.1.	Financial instruments, classified by type and category	69
	20.2.	Derivative instruments	70
	20.3.	Fair Value Hierarchies	73

21.	TRADE AND OTHER PAYABLES		74

22.	PROVISIONS		74

23.	EMPLOYMENT BENEFIT OBLIGATIONS		75
	23.1.	General information	75
	23.2.	Details, changes, and presentation in financial statements	76
	23.3.	Other disclosures	79

24.	EQUITY		79
	24.1.	Equity attributable to shareholders of Enersis	79
	24.2.	Foreign currency translation	81
	24.3.	Capital management	81
	24.4.	Restrictions on subsidiaries’ transferring funds to the parent	81
	24.5.	Other reserves	82
	24.6.	Non-controlling interests	83
	24.7.	Capital increase	83

F-18


25.	REVENUES		84

26.	RAW MATERIALS AND CONSUMABLES USED		84

27.	EMPLOYEE BENEFITS EXPENSES		85

28.	DEPRECIATION, AMORTIZATION, AND IMPAIRMENT LOSSES		85

29.	OTHER EXPENSES		86

30.	OTHER GAINS (LOSSES)		86

31.	FINANCIAL RESULTS		86

32.	INCOME TAX		88

33.	SEGMENT INFORMATION		89
	33.1.	Segmentation criteria	89
	33.2.	Generation, distribution, and others	90
	33.3.	Countries	93
	33.4.	Generation and distribution by country	96

34.	THIRD PARTY GUARANTEES, OTHER CONTINGENT ASSETS AND LIABILITIES, AND OTHERS COMMITMENTS		102
	34.1.	Direct guarantees	102
	34.2.	Indirect guarantees	102
	34.3.	Lawsuits and arbitrations proceedings	103
	34.4.	Financial covenants	112
	34.5.	Other information	115

35.	PERSONNEL FIGURES		115

36.	SANCTIONS		115

37.	SUBSEQUENT EVENTS		117

38.	ENVIRONMENT		118

39.	SUMMARIZED FINANCIAL INFORMATION ON PRINCIPAL SUBSIDIARIES AND JOINT VENTURES		119



APPENDIX 1	ENERSIS GROUP COMPANIES	120

APPENDIX 2	CHANGES IN SCOPE OF CONSOLIDATION	124

APPENDIX 3	ASSOCIATED COMPANIES	124

APPENDIX 4	ADDITIONAL INFORMATION ON FINANCIAL DEBT	125

APPENDIX 5	DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY	133

APPENDIX 6	ADDITIONAL INFORMATION OFICIO CIRCULAR (OFFICIAL BULLETIN) NO. 715 OF FEBRUARY 3, 2012	135

APPENDIX 6.1	COMPLEMENTARY INFORMATION ON TRADE RECEIVABLES	138

F-19

ENERSIS S.A. AND SUBSIDIARIES

Consolidated Financial Statements

for the years ending December 31, 2012 and 2011

(In thousands of Chilean pesos)

1.	THE GROUP’S ACTIVITIES AND FINANCIAL STATEMENTS

Enersis S.A. (hereinafter the Parent Company or the Company) and its subsidiaries comprise the Enersis Group (hereinafter Enersis or the Group).

Enersis S.A. is a publicly traded corporation with registered address and head office located at Avenida Santa Rosa, No. 76, in Santiago, Chile. The Company is registered in the securities register of the Superintendency of Securities and Insurance of Chile (Superintendencia de Valores y Seguros or SVS) under number 175. In addition, the Company is registered with the Securities and Exchange Commission of the United States of America (hereinafter U.S. SEC) and with Spain’s Comisión Nacional del Mercado de Valores. The Company’s shares have been listed on the New York Stock Exchange since 1993 and on the Latibex since 2001.

Enersis S.A. is a subsidiary of Endesa, S.A., a Spanish company controlled by Enel S.p.A. (hereinafter Enel).

The Company was initially created in 1981 under the corporate name of Compañía Chilena Metropolitana de Distribución Eléctrica S.A. Later on, the Company changed its by-laws and its name to Enersis S.A. effective August 1, 1988. For tax purposes, the Company operates under Chilean tax identification number 94,271,000-3.

As of December 31, 2012, the Group had 11,087 employees. During 2012, the Group averaged a total of 11,028 employees. See Note 35 for additional information regarding employee distribution by category and geographic location.

The Company’s corporate purpose consists of exploring for, developing, operating, generating, distributing, transmitting, transforming, and/or selling energy in any of its forms, whether in Chile or abroad, either directly or through another company. It is also engaged in telecommunications activities, and it provides engineering consultation services in Chile and abroad. The Company’s corporate purpose also includes investing in, and managing its investments in, subsidiaries and associates that generate, transmit, distribute, or sell electricity, or whose corporate purpose includes any of the following:

(i)

energy in any kind or form,

(ii)

supplying public services, or services whose main component is energy,

(iii)

telecommunications and information technology services, and

(iv)

Internet-based intermediation business.

The Company’s 2011 consolidated financial statements were approved by the Board of Directors at a meeting held on January 31, 2012. The consolidated financial statements were then submitted to the consideration of a General Shareholders Meeting held on April 26, 2012, which gave its final approval on the consolidated financial statements.

These consolidated financial statements are presented in thousands of Chilean pesos (unless expressly stated otherwise), as the Chilean peso is the functional currency of the main economic environment in which Enersis operates. Foreign operations are reported in accordance with the accounting policies stated in Notes 2.6 and 3.m.

2.	BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

2.1

Accounting principles

The December 31, 2012 consolidated financial statements of Enersis and its subsidiaries have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Boards (hereinafter “IASB”), and approved by its Board of Directors at its meeting held on January 30, 2013.

These consolidated financial statements present fairly the financial position of Enersis and its subsidiaries as of December 31, 2012 and 2011, as well as the results of operations, the changes in equity, and the cash flows for the years ending December 31, 2012, 2011 and 2010.

F-20

These consolidated financial statements voluntarily present the 2010 fiscal year figures for the consolidated statements of comprehensive income, the consolidated statement of cash flow, the consolidated statement of changes in net equity, and the corresponding notes.

These consolidated financial statements have been prepared using cost method accounting applied to the business in operation principle except, in accordance with IFRS, those assets and liabilities that are reported at a fair value and those non-current assets and groups that are available for sale, which are recorded at the book value or the fair value minus sales costs, whichever is lower (see Note 3).

These consolidated financial statements have been prepared from accounting records maintained by the Company and its subsidiaries. Each entity prepares its financial statements according to the accounting principles and standards in force in each country, so the necessary adjustments and reclassifications have been made in the consolidation process in order to present the consolidated financial statements in accordance with IFRS and the interpretations of the IFRS Interpretation Committee (hereinafter IFRIC).

2.2

New accounting pronouncements

Accounting pronouncements effective from January 1, 2012:


Standards, Interpretations, and Amendments				Mandatory application for:

Amendment to IFRS 7: Financial Instruments: Disclosures
Modifies the disclosure requirements when financial assets are transferred to promote transparency and to facilitate an analysis of the risks may affect the entity’s financial situation.				Annual periods beginning on or after July 1, 2011
Amendment to IAS 12: Income taxes
Provides an exception to the general principles of IAS 12 for investment properties measured using the fair value model contained in IAS 40, “Investment Properties.”				Annual periods beginning on or after January 1, 2012

The application of these accounting pronouncements has not had any significant effects for the Group. The other accounting criteria applied in 2012 have not changed with respect to those used in 2011.

F-21

Accounting principles effective from January 1, 2013:

As of the issuance date of these consolidated financial statements, the following accounting pronouncements had been issued by the IASB, but they were not yet mandatory:


Standards, Interpretations, and Amendments				Mandatory application for:

Amendment to IAS 1: Presentation of financial statements Modifies aspects of presenting the components of “Other comprehensive income,” requiring that these components be grouped into those that will and those that will not subsequently be reclassified as losses and gains.				Annual periods beginning on or after July 1, 2012

IFRS 10: Consolidated financial statements Establishes clarifications and new parameters for defining control, as well as the principles for preparing consolidated financial statements that apply to all entities (including special purpose entities or structured entities).				Annual periods beginning on or after January 1, 2013

IFRS 11: Joint agreements Redefines the concept of joint control, aligning with IFRS 10 and requiring that entities that are part of a joint agreement determine the type of agreement (joint operation or joint venture) by evaluating their rights and obligations. The standard eliminates the possibility of proportional consolidation for joint ventures).				Annual periods beginning on or after January 1, 2013

IFRS 12: Disclosures of interest held in other entities Requires certain disclosures that allow for assessing the nature of the stake held in other entities and the risks involved, as well as how these interest affect the entity’s financial situation, financial performance, and cash flows.				Annual periods beginning on or after January 1, 2013

IFRS 13: Measurement of fair value Establishes, in a single standard, a framework for assessing the fair value of assets and liabilities, and incorporates new concepts and clarifications for this assessment. It also requires that the entities disclose certain information on the assessment of the fair value of their assets and liabilities.				Annual periods beginning on or after January 1, 2013

New IAS 27: Separate financial statements When IFRS 10 was issued, it eliminated from IAS 27 everything connected with consolidated financial statements, restricting its scope only to separate financial statements.				Annual periods beginning on or after January 1, 2013

New IAS 28: Investments in associated companies and joint business Modified by the effect of the issuance of IFRS 10 and IFRS 11 in order to make the definitions and other clarifications contained in these new IFRS consistent.				Annual periods beginning on or after January 1, 2013

Amendment to IFRS 7: Financial instruments: Disclosures Clarifies the disclosure requirements for the offsetting of financial assets and liabilities.				Annual periods beginning on or after January 1, 2013

F-22


Standards, Interpretations, and Amendments				Mandatory Application for:

Amendment to IAS19: Employee benefits Modifies recognition and disclosure of changes in the obligations from defined benefit plans and in the assets affected by the plan, eliminating the corridor method and accelerating recognition of costs from past services.				Annual periods beginning on or after January 1, 2013

Amendment to IAS 32: Financial instruments: Presentation Clarifies the requirements for the offsetting of financial assets and financial liabilities in order to eliminate the inconsistencies from applying the current IAS 32 criteria for offsetting.				Annual periods beginning on or after January 1, 2014

IFRS 9: Financial instruments: Classification and measurement The first stage of the IASB project to replace IAS 39, “Financial Instruments: Recognition and Measurement.” Modifies classification and measurement of financial assets and includes treatment and classification of financial liabilities.				Annual periods beginning on or after January 1, 2015.

Improvements to the IFRS A series of improvements that are necessary but not urgent and that modify the following standards: IFRS 1, IAS 1, IAS 16, IAS 32, and IAS 34.				Annual periods beginning on or after January 1, 2013

Transition Guide (Amendments to IFRS 10, 11, and 12) These amendments clarify the transition guide for IFRS 10. They also simplify the transition of IFRS 10, IFRS 11, and IFRS 12, limiting the requirements to provide adjusted comparative information to the preceding comparative period only. In addition, for disclosures related to entities with non-consolidated structures, the amendments remove the requirement to present comparative information for periods prior to the first application of IFRS 12.				Annual periods beginning on or after January 1, 2013

Amendments to IFRS 10 & 12 and IAS 27: Investment entities Under IFRS 10 requirements, reporting entities are required to consolidate all of the companies over which they have control. The amendment establishes an exception to these requirements that allows Investment Entities to to measure this investments at fair value through profit or loss in accordance with IFRS 9 “Financial Instruments.”				Annual periods beginning on or after January 1, 2014

As a result of the application of IFRS 11, Joint Agreements, as of January 1, 2013, joint ventures companies, which were consolidated on a proportional basis until the close of these financial statements (see Notes 2.4 and 2.6), will be accounted for using the equity method, as required under the new standard for joint agreements that qualify as Joint Venture.

The Group is assessing the impact of applying IFRS 9 from the date it goes into effect. In Management’s opinion, the application of other standards, interpretations, and amendments pending application will not have a significant effect on the consolidated financial statements of Enersis and its subsidiaries.

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The following table presents the main accounts in Enersis’ consolidated financial statements in order to reflect the effects of retroactively applying IFRS 11, Joint Agreements:


Consolidated Statement of Financial Position	12-31-2012 Actual ThCh$			12-31-2011 With IFRS 11 ThCh$

Current assets		2,354,518,433			2,290,188,930
Non-current assets		10,963,315,207			10,947,105,000

Total assets		13,317,833,640			13,237,293,930

Current liabilities		2,381,112,235			2,346,730,725
Non-current liabilities		3,972,952,827			3,932,356,159
Equity attributable to shareholders of Enersis		3,893,798,571			3,893,798,572
Non-controlling interests		3,069,970,007			3,064,408,474

Total liabilities and equity		13,317,833,640			13,237,293,930

Consolidated Income Statement

Total revenues		6,577,667,314			6,495,953,449
Raw materials and fuel consumption		(3,717,125,487	)		(3,695,022,919	)
CONTRIBUTION MARGIN		2,860,541,827			2,800,930,530

Gross Operating Result		1,982,924,464			1,947,859,229
Depreciation, amortization, and impairment losses		(485,959,916	)		(477,096,461	)
Operating income		1,496,694,548			1,470,762,768
Net income before tax		1,305,453,216			1,299,688,888
Net income attributable to shareholders of Enersis		377,350,521			377,350,521
Net income attributable to non-controlling interests		516,211,461			515,662,446
Net Income		893,561,982			893,012,967

2.3 Responsibility for the information and estimates made

The Company’s Board of Directors is responsible for the information contained in these consolidated financial statements and expressly states that all IFRS principles and standards have been fully implemented.

In preparing the consolidated financial statements, certain estimates made by the Company’s Management have been used to quantify some of the assets, liabilities, income, expenses, and commitments recorded in the statements

These estimates basically refer to:

The valuation of assets and goodwill to determine the existence of impairment losses (see Note 3.e).

The assumptions used to calculate the actuarial liabilities and obligations to employees, such as discount rates, mortality tables, salary raises, etc. (see Notes 3.l.1 and 23).

The useful life of property, plant and equipment, and intangible assets (see Notes 3.a and 3.d).

The assumptions used to calculate the fair value of financial instruments (see Notes 3.g.5 and 20).

Energy supplied to customers whose meter readings are pending.

Certain assumptions inherent in the electricity system affecting transactions with other companies, such as production, customer billings, energy consumption, etc. that allow for estimating electricity system settlements that must occur on the corresponding final settlement dates, but that are pending as of the date of issuance of the consolidated financial statements and could affect the balances of assets, liabilities, income and expenses recorded in the statements.

The probability that uncertain or contingent liabilities will be incurred and their related amounts (see Note 3.l).

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Future disbursements for the closure of facilities and restoration of land (see Note 3.a).

The tax results of the various subsidiaries of the Group that will be reported to the respective tax authorities in the future, and that have served as the basis for recording different balances related to income taxes in these consolidated financial statements (see Note 3.o).

Although these estimates have been based on the best information available on the issuance date of these consolidated financial statements, future events may occur that would require a change (increase or decrease) to these estimates in subsequent periods. This change would be made prospectively, recognizing the effects of such an estimation change in the corresponding future consolidated financial statements.

2.4

Subsidiaries and joint ventures

Subsidiaries are defined as entities in which the Parent Company controls the majority of the voting rights or, should that not be the case, is authorized to direct the financial and operating policies of such entities.

Joint ventures are those in which the situation described in the preceding paragraph exists as a result of an agreement with other shareholders and control is exercised jointly with them.

Appendix 1 of these consolidated financial statements, entitled Enersis Group Companies, describes Enersis’ relationship with each of its subsidiaries and joint ventures.

2.4.1

Changes in the scope of consolidation

During 2012 there were no significant changes in the Enersis Group’s scope of consolidation.

The process of selling the companies Compañía Americana de Multiservicios (CAM) and Synapsis Servicios y Soluciones Informáticas IT (Synapsis) was completed during the first quarter of 2011. The sale of CAM was concluded on February 24, 2011 for the amount of ThCh$ 6,775,748 (US$ 14.2 million), while the sale of Synapsis was finalized on March 1, 2011 for ThCh$ 24,710,920 (US$ 52 million). For more information, see Note 11.

The elimination of CAM and Synapsis from the Enersis consolidated statements has resulted in reductions in the consolidated statement of financial position of ThCh$ 80,050,947 in current assets, ThCh$ 31,003,337 in non-current assets, ThCh$ 56,359,935 in current liabilities, and ThCh$ 14,558,579 in non-current liabilities.

The section titled “Changes in the Enersis Group Scope of Consolidation,” included as Appendix No. 2 to these consolidated financial statements, lists the companies included within the scope of the Group’s consolidation, together with information on the Group’s respective ownership interest percentages.

2.4.2

Consolidated companies with an ownership interest of less than 50%

Although the Enersis Group holds less than a 50% interest in Compañía Distribuidora y Comercializadora de Energía S.A. ESP (Codensa) and in Empresa Generadora de Energía Eléctrica S.A. ESP(Emgesa), they are considered subsidiaries since the Group exercises control over the entities, either directly or indirectly, through contracts or agreements with shareholders, or as a consequence of their structure, composition, and shareholder classes.

2.4.3

Non-consolidated companies with an ownership interest of over 50%

Although the Enersis Group holds more than a 50% interest in Centrales Hidroeléctricas de Aysén S.A. (Aysén), it is considered a joint venture since the Group, through contracts and agreements with shareholders, exercises joint control of the company.

2.5

Associated companies

Associated Companies are those in which Enersis, either directly or indirectly, exercises significant influence. In general, significant influence is assumed to be those cases in which the Group has an ownership interest of over 20% (see Note 3.h).

Appendix 3 to these consolidated financial statements, entitled “Associated Companies,” describes Enersis’ relationship with each associated company.

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2.6

Basis of consolidation and business combinations

The subsidiaries are consolidated and all their assets, liabilities, income, expenses, and cash flows are included in the consolidated financial statements once the adjustments and eliminations from intra-Group transactions have been made.

Joint ventures are consolidated using the proportional consolidation method. The Group recognizes, line by line, its share of the assets, liabilities, income, and expenses of such entities, so the adding of balances and subsequent eliminations take place only in proportion to the Group’s ownership interest in them.

The comprehensive income of subsidiaries and joint ventures is included in the consolidated comprehensive income statement from the effective date of acquisition until the effective date of disposal or termination of joint control, as applicable.

The parent company’s and its subsidiaries’ operations, as well as those of joint ventures, have been consolidated under the following basic principles:

At the date of acquisition, the assets, liabilities, and contingent liabilities of the subsidiary or joint venture are recorded at market value. If, in the parent company’s stake, there is a positive difference between the acquisition cost and the fair value of the assets and liabilities of the company acquired, including contingent liabilities, this difference is recorded as goodwill. If the difference is negative, it is recorded as a credit to income.

Non-controlling interests in equity and in the comprehensive income of the consolidated subsidiaries are presented, respectively, under the line items “Total Equity: Non-controlling interests” in the consolidated statement of financial position and “Net Income attributable to non-controlling interests” and “Comprehensive income attributable to non-controlling interests” in the consolidated statement of comprehensive income.

The financial statements of foreign companies with functional currencies other than the Chilean peso are translated as follows:

For assets and liabilities, the prevailing exchange rate on the closing date of the financial statements is used.

For items in the comprehensive income statement, the average exchange rate for the year is used (unless this average is not a reasonable approximation of the cumulative effect of the exchange rates in effect on the dates of the transactions, in which case the exchange rate in effect on the date of each transaction is used).

Equity remains at the historical exchange rate from the date of acquisition or contribution, and retained earnings at the average exchange rate at the date of generation.

Exchange differences arising in the conversion of the financial statements are recognized in the item “Exchange difference on translation” within the consolidated statement of comprehensive income: Other comprehensive income (see Note 24.2).

Translation adjustments that existed at Enersis’ transition date to IFRS, on January 1, 2004, were transferred to reserves, using the exemption for that purpose in IFRS 1 “First time Adoption of IFRS” (see Note 24.5).

All balances and transactions between consolidated companies, as well as the share of the proportionally consolidated companies, were eliminated in the consolidation process.

3.	ACCOUNTING PRINCIPLES APPLIED

The main accounting policies used in preparing the accompanying consolidated financial statements were the following:

Property, plant, and equipment

Property, plant and equipment are valued at acquisition cost, net of accumulated depreciation and any impairment losses they may have experienced. In addition to the price paid to acquire each item, the cost also includes, where applicable, the following concepts:

Financing expenses accrued during the construction period that are directly attributable to the acquisition, construction, or production of qualified assets, which require a substantial period of time before being ready for use such as, for example, electricity generation or distribution facilities. The Group defines “substantial period” as one that exceeds 12 months. The interest rate used is that of the specific financing or, if none exists, the mean financing rate of the company carrying out the investment. The mean financing rate depends principally on the geographic area and ranges between 7.22% and 10.16%. The amount capitalized for this concept amounted to ThCh$ 26,477,369, ThCh$ 35,945,738 and ThCh$ 15,137,380 for the years ended December 31, 2012, 2011, and 2010, respectively.

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Employee expenses directly related to construction in progress. The amounts capitalized under this concept for the periods ended December 31, 2012, 2011, and 2010 were ThCh$ 33,112,076, ThCh$ 32,042,815, and ThCh$ 26,741,111, respectively.

Future disbursements that the Group will have to make to close their facilities are incorporated into the value of the asset at present value, recording in the accounting the corresponding provision. The Group reviews its estimate of these future disbursements on a yearly basis, increasing or decreasing the value of the asset based on the results of this estimate (see Note 22).

Items acquired before the Group’s date of transition to IFRS, on January 1, 2004, include in the purchasing cost, where appropriate, asset reappraisals permitted in the various countries to adjust the value of the property, plant and equipment for inflation as of that date (see Note 24.5).

Items for construction work in progress are transferred to operating assets once the testing period has been completed and they are available for use, at which time depreciation begins.

Expansion, modernization, or improvement costs that represent an increase in productivity, capacity or efficiency, or a longer useful life are capitalized as a greater cost for the corresponding assets.

The replacement or overhaul of entire components that increase the asset’s useful life, or its economic capacity, are recorded as an increase in value for the respective assets, derecognizing the replaced or overhauled components.

Expenses for periodic maintenance, conservation, and repair are recorded directly in income as an expense for the year in which they are incurred.

The Company, based on the outcome of impairment testing explained in Note 3.e), considers that the book value of assets does not exceed their net recoverable value.

Property, plant, and equipment, net of its residual value, is depreciated by distributing the cost of the different items that comprise it on a straight-line basis over its estimated useful life, which is the period during which the companies expect to use the assets. Useful life estimates are periodically reviewed and, if appropriate, adjusted prospectively.

The following are the main categories of property, plant, and equipment with their respective estimated useful lives.


Categories of Property, plant, and equipment		Years of estimated useful life
Buildings		22-100
Plant and equipment		3-65
IT equipment		3-15
Fixtures and fittings		5-21
Motor vehicles		5-10
Other		2-33

Additionally, the following provides greater detail on the useful lives of plant and equipment items:


		Years of estimated useful life
Generating facilities:
Hydroelectric power plants
Civil engineering works		35-65
Electromechanical equipment		10-40
Coal-fired / fuel-oil power plants		25-40
Combined cycle plants		10-25
Renewable energy power plants		35
Transmission and distribution facilities:
High-voltage network		10-60
Low- and medium-voltage network		10-60
Measuring and remote control equipment		3-50
Other facilities		4-25

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Regarding the administrative concessions held by the Group’s electric companies, the following lists the years remaining until expiration for the concessions that do not have an indefinite term:


Concession holder and operator	Country	Concession term	Period remaining until expiration
Empresa Distribuidora Sur S.A. - Edesur (Distribution)	Argentina	95 years	75 years
Hidroeléctrica El Chocón S.A. (Generation)	Argentina	30 years	11 years
Transportadora de Energía S.A. (Transmission)	Argentina	85 years	75 years
Compañía de Transmisión del Mercosur S.A. (Transmission)	Argentina	87 years	75 years
Central Eléctrica Cachoeira Dourada S.A. (Generation)	Brazil	30 years	15 years
Central Geradora Termeléctrica Fortaleza S.A. (Generation)	Brazil	30 years	19 years
Companhia de Interconexao Energética S.A. (CIEN - Line 1)	Brazil	20 years	8 years
Companhia de Interconexao Energética S.A. CIEN - Line 2)	Brazil	20 years	10 years

The Group’s management evaluated the specific contract term of each of the aforementioned concessions, which vary by country, business activity, and jurisprudence, and concluded that, with the exception of CIEN, there are no determining factors indicating that the grantor, which in every case is a government entity, controls the infrastructure and, at the same time, can continuously set the price to be charged for services. These requirements are essential for applying IFRIC 12 “Service Concession Agreements,” which establishes how to record and value certain types of concessions (see Note 3.d.1 for concession agreements within the scope of IFRIC 12).

On April 19, 2011, our subsidiary CIEN successfully completed the change in business model that we had previously been reporting. Under the new agreement, the Government continues to control the infrastructure, but CIEN receives fixed payments, which puts it on an equal footing with a public transmission concession (with regulated prices).

Under this business model, its concessions fall within the scope of Standard IFRIC 12, but the infrastructure has not been derecognized due to the fact that CIEN has not substantially transferred the significant risks and benefits to the Brazilian Government.

Concession contracts not covered under IFRIC 12 are recognized according to general criteria. To the extent that the Group recognizes assets as property, plant, and equipment, they are amortized over their economic life or the concession term, whichever is shorter. Any required investment, improvement, or replacement made by the Group is calculated as an impairment to Property, Plant, and Equipment as a future contractual cash outflow that is necessary to obtain future cash inflow.

Gains or losses that arise from the sale or disposal of items of property, plant and equipment are recognized in income for the period and calculated as the difference between the sale value and the net book value.

Investment property

“Investment property” includes primarily land and buildings held for the purpose of earning rental income and/or for capital appreciation.

Investment property is valued at acquisition cost less any accumulated depreciation and impairment losses that have been incurred. Investment property, excluding land, is depreciated on a straight-line basis over the useful lives of the related assets.

The breakdown of the fair value of investment property is detailed in Note 16.

Goodwill

Goodwill generated upon consolidation represents the difference between the acquisition cost and the Group’s share of the fair value of assets and liabilities, including identifiable contingent liabilities of a subsidiary at the acquisition date.

Acquired assets and liabilities are temporarily valued as of the date the company takes control and reviewed within no more than a year after the acquisition date. Until the fair value of assets and liabilities is ultimately determined, the difference between the acquisition price and the book value of the acquired company is temporarily recorded as goodwill.

If goodwill is finally determined as existing in the financial statements the year following the acquisition, the prior year’s accounts, which are presented for comparison purposes, are modified to include the value of the acquired assets and liabilities and of the definitive goodwill from the acquisition date.

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Goodwill generated from acquiring companies with functional currencies other than the Chilean peso is valued in the functional currency of the acquired company and converted to Chilean pesos using the exchange rate in effect as of the date of the statement of financial position.

Goodwill generated before the date of transition to IFRS, on January 1, 2004, is maintained at its net value recorded as of that date, while goodwill originated afterwards is valued at acquisition cost (see Notes 14 and 24.5).

Goodwill is not amortized; instead, at each period end the Company estimates whether any impairment has reduced its recoverable value to an amount less than the net recorded cost and, if so, it immediately adjusts for impairment (see Note 3.e).

Intangible assets other than goodwill

Intangible assets are initially recognized at their acquisition or production cost, and are subsequently valued at their cost, net of their accumulated amortization and of the impairment losses they may have experienced.

Intangible assets are amortized on a straight line basis during their useful life, starting from the time that they are in usable condition, except for those with an indefinite useful life, which are not amortized. As of December 31, 2012, there were no significant amounts in intangible assets with an indefinite useful life.

The criteria for recognizing these assets’ impairment losses and, if applicable, recovery of impairment losses recorded in previous fiscal years are explained in letter e) of this Note.

d.1)

Concessions

IFRIC 12, “Service Concession Agreements,” provides accounting guidelines for public-to-private service concession agreements. This accounting interpretation applies if:

The grantor controls or regulates which services the operator should provide with the infrastructure, to whom it must provide them, and at what price; and

The grantor controls – through ownership, beneficial entitlement, or otherwise – any significant residual interest in the infrastructure at the end of the term of the agreement.

If both of the above conditions are met simultaneously, the consideration received by the Group for the infrastructure construction is recognized at its fair value, as either an intangible asset when the Group receives the right to charge users of the public service, as long as these charges are conditional on the degree to which the service is used; or as a financial asset when the Group has an unconditional contractual right to receive cash or other financial asset from the grantor or a third party. The Group recognizes the contractual obligations assumed for maintenance of the infrastructure during its use, or for its return to the grantor at the end of the concession agreement within the conditions specified in the agreement, as long as it does not involve an activity that generates income, in accordance with the Group’s provision accounting policy (see Note 3.l).

Finance expenses attributable to the concession agreements are capitalized based on criteria established in Note 3 a) above, provided that the Group has a contractual right to receive an intangible asset. No finance expenses were capitalized during the fiscal years ended December 31, 2012, 2011, and 2010.

Additionally, during the years ended December 31, 2012, 2011, and 2010, employee expenses directly attributable to construction in progress, amounting to ThCh$ 15,741,611, ThCh$ 18,130,297, and ThCh$ 18,128,254, respectively, were capitalized.

The subsidiaries that have recognized an intangible asset from their service concession agreements are the following:


Concession holder and operator	Country	Term	Period remaining to expiration
Ampla Energía e Serviços S.A. (*) (Distribution)	Brazil	30 years	14 years
Companhia Energética do Ceará S.A. (*) (Distribution)	Brazil	30 years	15 years
Concesionaria Túnel El Melón S.A. (Highway Infrastructure)	Chile	23 years	4 years

(*) Considering that part of the rights acquired by our subsidiaries are unconditional, an asset for available-for-sale financial investments has been recognized (see Notes 3.g.1 and 6).

F-29

d.2)

Research and development expenses

The Group follows the policy of recording the costs incurred in a project’s development phase as intangible assets in the statement of financial position as long as the project’s technical viability and economic returns are reasonably assured.

Expenditures on research activities are recognized as an expense in the period in which they are incurred. These expenses amounted to ThCh$ 2,298,344, ThCh$ 2,104,631, and ThCh$ 2,460,261 as of December 31, 2012, 2011, and 2010, respectively.

d.3)

Other intangible assets

These intangible assets correspond primarily to computer software, water rights, and easements. They are initially recognized at acquisition or production cost and are subsequently measured at cost less accumulated amortization and impairment losses, if any.

Computer software programs are amortized, on average, over five years. Certain easements and water rights have indefinite useful lives and are therefore not amortized, while others have useful lives ranging from 40 to 60 years, depending on their characteristics, and they are amortized over that term.

Asset impairment

During the year, and principally at year-end, the Company evaluates whether there is any indication that an asset has been impaired. Should any such indication exist, the company estimates the recoverable amount of that asset to determine the amount of impairment in each case. In the case of identifiable assets that do not generate cash flows independently, the company estimates the recoverability of the Cash Generating Unit to which the asset belongs, which is understood to be the smallest identifiable group of assets that generates independent cash inflows.

The recoverable amount is the greater amount between the fair value less the cost needed to sell and the value in use, which is defined as the present value of the estimated future cash flows. In order to calculate the recoverable value of Property, plant, and equipment, goodwill and intangible assets, the Group uses value in use criteria in practically all cases.

To estimate the value in use, the Group prepares future cash flow projections, before tax, based on the most recent budgets available. These budgets incorporate management’s best estimates of Cash Generating Units’ revenue and costs using sector projections, past experience, and future expectations.

In general, these projections cover the next ten years, estimating cash flows for subsequent years by applying reasonable growth rates which, in no case, are increasing nor exceed the average long-term growth rates for the particular sector and country. At the end of 2012 and 2011, projections were extrapolated from the following rates:


Country	Currency	Growth Rates (g)
Country	Currency	2012	2011
Chile	Chilean peso	2.3% - 5.2%	4.2% - 5.3%
Argentina	Argentine peso	8.6% - 9.5%	7.0% - 7.9%
Brazil	Brazilian real	5.1% - 6.1%	5.0% - 6.0%
Peru	Peruvian sol	3.7% - 4.9%	3.2% - 4.3%
Colombia	Colombian peso	4.3% - 5.3%	4.4% - 5.2%

These flows are discounted to calculate their current value at a before-tax rate that covers the cost of capital for the business activity and the geographic area in which it is being carried out. The current cost of money and the risk premiums generally used among analysts for the business activity and the geographic zone are taken into account to calculate this value.

F-30

The following are the before-tax discount rates applied in 2012 and 2011, expressed in nominal terms:


Country	Currency	2012		2011
Country	Currency	Minimum	Maximum	Minimum	Maximum
Chile	Chilean peso	8.0%	14.6%	8.0%	10.1%
Argentina	Argentine peso	26.0%	29.0%	23.0%	26.0%
Brazil	Brazilian real	9.5%	18.0%	9.5%	11.6%
Peru	Peruvian sol	7.6%	12.5%	7.3%	9.3%
Colombia	Colombian peso	8.4%	14.5%	8.9%	10.9%

The following procedure is used to determine the need to adjust financial assets for impairment:

–

In the case of commercial assets, in both our generation and transmission segment and the electricity distribution segment, the Group’s policy is to record impairment through an allowance account based on the age of past-due balances. This policy is generally applied except in those cases where a specific collectability analysis is recommended, such as in the case of receivables from publically owned companies.

–

In the case of receivables of a financial nature, impairment is determined on case-by-case basis. As of the date of issuance of these consolidated financial statements, the Company had no significant past due non-commercial financial assets.

Leases

The Group applies IFRIC 4 to assess whether an agreement is, or contains, a lease. Leases that transfer to the lessee substantially all of the risks and rewards inherent in ownership are classified as finance leases. All other leases are classified as operating leases.

Finance leases in which the Group acts as a lessee are recognized when the agreement begins. At that time, the Group records an asset based on the nature of the lease and a liability for the same amount, equal to the fair value of the leased asset or the present value of the minimum lease payments, if the latter is lower. Subsequently, the minimum lease payments are divided between finance expense and principal reduction. The finance expense is recorded in the income statement and distributed over the lease term, so as to obtain a constant interest rate for each period over the balance of the debt pending amortization. The asset depreciates on the same terms as other similar depreciable assets, as long as there is reasonable certainty that the lessee will acquire ownership of the asset at the end of the lease. If no such certainty exists, the asset depreciates over the shorter term between the useful life of the asset and the term of the lease.

Operating lease payments are expensed on a straight-line basis over the term of the lease unless another type of systematic basis of distribution is deemed more representative.

Financial instruments

Financial instruments are contracts that give rise to both a financial asset in one company and a financial liability or equity instrument in another company.

g.1) Financial assets other than derivatives

The Group classifies its financial assets other than derivatives, whether permanent or temporary, except for investments accounted for using the equity method (see Note 12) and those held for sale (Note 11), into four categories:

Trade and other current receivables and Accounts receivable from related companies: These are recorded at amortized cost, which is the initial fair value less principal repayments made, plus accrued and uncharged interest, calculated using the effective interest method.

F-31

The effective interest method is used to calculate the amortized cost of a financial asset or liability (or group of financial assets or financial liabilities) and is charged to finance income or cost over the relevant period. The effective interest rate is the discount rate that exactly matches the estimated cash flows to be received or paid over the expected life of the financial instrument (or, when appropriate, over a shorter period) to the net carrying amount of the financial asset or financial liability.

Held-to-maturity investments: Investments that the Group intends to hold and is capable of holding until their maturity is accounted for at amortized cost as defined in the preceding paragraph.

Financial assets at fair value with changes in net income: This includes the trading portfolio and those financial assets that have been designated as such upon initial recognition and that are managed and evaluated using fair value criteria. They are valued in the consolidated statement of financial position at fair value, with changes in value recorded directly in income when they occur.

Available-for-sale financial assets: These are financial assets specifically designated as available for sale or that do not fit within any of the three preceding categories (see Note 6).

These investments are recorded in the consolidated statement of financial position at fair value when it can be reliably determined. For interests in unlisted companies or companies with very little liquidity, normally the market value cannot be reliably determined. When this occurs, those interests are valued at acquisition cost or a lesser amount if evidence of impairment exists.

Changes in fair value, net of tax, are recorded in the consolidated statement of comprehensive income: Other comprehensive results, until the investments are disposed of, at which time the amount accumulated in this account for that investment is fully charged to the period’s profit or loss.

Should the fair value be less than the acquisition cost, and if there is objective evidence that the asset has been more than temporarily impaired, the difference is recorded directly in the period’s losses.

Purchases and sales of financial assets are accounted for using their trade date.

g.2) Cash and cash equivalents

This account within the statement of consolidated financial position includes cash and bank balances, time deposits, and other highly liquid investments with a maturity of three months or less when acquired, readily convertible to cash and which are subject to insignificant risk of changes in value.

g.3) Financial liabilities other than derivatives

Financial liabilities are generally recorded based on cash received, net of any costs incurred in the transaction. In subsequent periods, these obligations are valued at their amortized cost, using the effective interest rate method (see Note 3.g.1).

In the particular case that a liability is the underlying item of a fair value hedge derivative, as an exception, such liability will be valued at its fair value for the portion of the hedged risk.

In order to calculate the fair value of debt, both in the cases when it is recorded in the statement of financial position and for fair value disclosure purposes as seen in Note 20, debt has been divided into fixed interest rate debt (hereinafter “fixed-rate debt”) and variable interest rate debt (hereinafter “floating-rate debt”). Fixed-rate debt is that on which fixed-interest coupons established at the beginning of the transaction are paid explicitly or implicitly over its term. Floating-rate debt is that issued at a variable interest rate, i.e., each coupon is established at the beginning of each period based on the reference interest rate. All debt has been valued by discounting expected future cash flows with a market-interest rate curve based on the payment’s currency.

g.4) Derivative financial instruments and hedge accounting

Derivatives held by the Group are primarily transactions entered into to hedge interest and/or exchange rate risk, intended to eliminate or significantly reduce these risks in the underlying transactions being hedged.

Derivatives are recorded at fair value as of the date of the statement of financial position as follows: if their fair value is positive, they are recorded within “Other financial assets”; and if their fair value is negative, they are recorded within “Other financial liabilities.” For derivatives on commodities, the positive value is recorded in “Trade and other current receivables,” and negative values are recorded in “Trade and other current liabilities.”

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Changes in fair value are recorded directly in income except when the derivative has been designated for accounting purposes as a hedge instrument and all of the conditions established under IFRS for applying hedge accounting are met, including that the hedge be highly effective. In this case, changes are recorded as follows:

Fair value hedges: The underlying portion for which the risk is being hedged is valued at its fair value, as is the hedge instrument, and any changes in the value of both are recorded in the comprehensive income statement by netting the effects in the same comprehensive income statement account.

Cash flow hedges: Changes in the fair value of the effective portion of derivatives are recorded in an equity reserve known as “Reserve of cash flow hedges.” The cumulative loss or gain in this account is transferred to the comprehensive income statement to the extent that the underlying item impacts the comprehensive income statement because of the hedged risk, netting the effect in the same comprehensive income statement account. Gains or losses from the ineffective portion of the hedge are recorded directly in the comprehensive income statement.

A hedge is considered highly effective when changes in the fair value or in the cash flows of the underlying item directly attributable to the hedged risk are offset by changes in the fair value or the cash flows of the hedging instrument, with effectiveness ranging from 80% to 125%.

The Company does not apply hedge accounting to its investments abroad.

As a general rule, long-term commodity purchase or sale agreements are recorded in the consolidated statement of financial position at their fair value as of period end, recording any differences in value directly in income, except when all of the following conditions are met:

The sole purpose of the agreement is for the Group’s own use.

The Group’s future projections justify the existence of these agreements for its own use.

Past experience with agreements shows that they have been utilized for the Group’s own use, except in certain isolated cases when they had to be used for exceptional reasons or reasons associated with logistical issues beyond the control and projection of the Group.

The agreement does not stipulate settlement by differences and the parties do not make it a practice to settle similar contracts by differences in the past.

The long-term commodity purchase or sale agreements maintained by the Group, which are mainly for electricity, fuel, and other supplies, meet the conditions described above. Thus, the purpose of fuel purchase agreements is to use them to generate electricity, the electricity purchase contracts are used to make sales to end-customers, and the electricity sale contracts are used to sell the company’s own product.

The Company also evaluates the existence of derivatives embedded in contracts or financial instruments to determine if their characteristics and risk are closely related to the principal contract, provided that when taken together they are not being accounted for at fair value. If they are not closely related, they are recorded separately and changes in value are accounted for directly in the comprehensive income statement.

g.5) Fair value measurement and classification of financial instruments

The fair value of the various derivative financial instruments is calculated as follows:

For derivatives traded on a formal market, by its quoted price as of year-end.

The Group values derivatives not traded on formal markets by using discounted expected cash flows and generally accepted options valuation models, based on current and future market conditions as of year-end.

Using the procedures described, the Group classifies financial instruments at the following levels:


Level 1:		Quoted price (unadjusted) in active markets for identical assets or liabilities;

Level 2:		Inputs other than quoted prices included within Level 1 that are observable for the assets or liabilities, either directly (i.e. as prices) or indirectly (i.e. derived from prices); and

Level 3:		Inputs for assets or liabilities that are not based on observable market data (unobservable inputs).

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g.6) Derecognition of financial assets

Financial assets are derecognized when:

The contractual rights to receive cash flows related to the financial asset expire or have been transferred or, if the contractual rights are retained, the Group has assumed a contractual obligation to pay these cash flows to one or more receivers.

The Group has substantially transferred the risks and rewards of ownership of the financial asset, or, if it has neither transferred nor retained substantially all the risks and rewards, when it does not retain control over the asset.

Transactions in which the Group retains substantially all the inherent risks and rewards of ownership of the transferred asset, it continues recognizing the transferred asset in its entirety and recognizes a financial liability for the consideration received. Transactions costs are recognized in profit and loss by using the effective interest method (see Note 3.g.1).

Investments accounted for using the equity method

Investments in associates in which the Group has significant influence are recorded using the equity method.

The equity method consists of recording the investment in the statement of financial position based on the share of its equity that the Group’s interest represents in its capital, adjusted for, if appropriate, the effect of transactions with subsidiaries plus any goodwill generated in acquiring the company. If the resulting amount is negative, zero is recorded for that investment in the statement of financial position, unless there is a commitment from the Group to support the company’s negative equity situation, in which case a provision is recorded.

Dividends received from these companies are deducted from the value of the investment, and any profit or loss obtained from them to which the Group is entitled based on its interest is recorded under “Share of profit (loss) of associates accounted for using equity method.”

Appendix No. 3, “Enersis Group Associated Companies,” included in these consolidated financial statements, provides information about Enersis’ relationship with each of its associates.

Inventories

Inventories are valued at their weighted average acquisition price or the net realizable value, whichever is lower.

Non-current assets held for sale and discontinued operations

The Group classifies the following as “Non-current assets held for sale”: property, plant and equipment; intangible assets; investments accounted for using the equity method and disposal groups (a group of assets to be disposed of and the liabilities directly associated with those assets), if as of the date of the consolidated financial statements, the Group has taken active measures for their sale and estimates that such a sale is highly probable.

These held-for-sale assets or disposal groups are valued at the lower of their book value or fair value less selling costs. Depreciation and amortization on these assets cease when they meet the criteria to be classified as held for sale.

Non-current assets held for sale and the components of the disposal groups classified as held for sale are presented in these consolidated statement of financial position as a single line item within assets called “Non-current assets or disposal groups classified as held for sale,” and the respective liabilities are presented as a single line item within liabilities called “Liabilities included in disposal groups classified as held for sale.”

The Group classifies as “Discontinued operations” those separate major lines of business that have been sold, or disposed of in another way, or those that may be classified as held for sale, including other assets that are part of the same coordinated sales or disposal plan. In the same way, entities that have been acquired solely in order to be resold are also considered “Discontinued operations.”

The components of profit or loss after taxes from discontinued operations are presented as a single line item in the consolidated comprehensive income statement as “Net income from discontinued operations.”

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Treasury shares

Treasury shares are deducted from equity in the consolidated statement of financial position and valued at acquisition cost.

The gains and losses from the disposal of treasury shares are recorded under the heading Total Equity – Retained earnings. As of December 31, 2012, there are no treasury shares, and no transactions with treasury shares were made during the 2012 and 2011 fiscal periods.

Provisions

Obligations existing as of the date of the consolidated financial statements resulting from past events which may negatively impact the Group’s equity, and whose amount and timing of payment are uncertain, are recorded as provisions in the consolidated statement of financial position at the present value of the most likely amount that it is believed that the Group will have to disburse to settle the obligation.

Provisions are quantified using the best information available as of the date of issuance of the consolidated financial statements regarding the consequences of the event causing the provision and are re-estimated at each subsequent accounting close.

l.1) Provisions for post-employment benefits and similar obligations

Some of the Group’s subsidiaries have pension and similar obligations to their employees. Such obligations, which combine defined benefits and defined contributions, are basically formalized through pension plans, except for certain non-monetary benefits, mainly electricity supply commitments, which, due to their nature, have not been externalized and are covered by the related in-house provisions.

For defined benefit plans, the cost of providing benefits is determined using the Projected Unit Credit Method, with actuarial valuations being carried out at the end of each reporting period. Past service costs relating to changes in benefits are recognized immediately to the extent that the benefits are already vested, and otherwise are amortized on a straight-line basis over the average period until the benefits become vested.

The defined benefit plan obligations in the statement of financial position represent the present value of the accrued obligations, adjusted, once the fair value of the different plans’ assets has been deducted, if applicable.

For each of the plans, any positive difference between the actuarial liability for past services and the plan assets is recognized under line item “Provisions for employee benefits” within current and non-current liabilities in the consolidated statement of financial position, and any negative difference is recognized under line item “Other financial assets” within non-current assets in the consolidated statement of financial position, provided that the negative difference is recoverable by the Group, usually through a reduction in future contributions and taking into consideration the limit established in IFRIC 14, “IAS 19 The limit on a defined benefit asset, minimum funding requirements, and their interaction.”

Contributions to defined contribution benefit plans are recognized as an expense in the consolidated statement of comprehensive income when the employees have rendered their services.

Actuarial gains and losses arising in the measurement of both the plan liabilities and the plan assets, including the limit in IFRIC 14, are recognized directly under “Equity - Retained earnings.”

Conversion of balances in foreign currency

Transactions carried out by each company in a currency other than its functional currency are recorded using the exchange rates in effect as of the date of each transaction. During the year, any differences that arise between the exchange rate recorded in accounting and the rate prevailing as of the date of collection or payment are recorded as “Foreign currency exchange differences” in the comprehensive income statement.

Likewise, at the end of each period, balances receivable or payable in a currency other than each company’s functional currency are converted using the period-end exchange rate. Any valuation differences are recorded as “Foreign currency exchange differences” in the comprehensive income statement.

The Group has established a policy to hedge the portion of its subsidiaries’ revenue that is directly linked to variations in the US dollar by obtaining financing in this currency. Exchange differences related to this debt, as they are cash flow hedge transactions, are charged, net of taxes, to a reserve account in equity and recorded in income during the period in which the hedged cash flows are realized. This term has been estimated at ten years.

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Current / non-current classification

In these consolidated statements of financial position, assets and liabilities expected to be recovered or settled within twelve months are presented as current items and those assets and liabilities expected to be recovered or settled in more than twelve months are presented as non-current items.

Should the Company have any obligations that mature in less than twelve months but can be refinanced over the long term at the Company’s discretion, through unconditionally available credit agreements with long-term maturities, such obligations have been classified as long-term liabilities.

Income tax

Income taxes for the period are determined as the sum of current taxes from the Group’s different subsidiaries and result from applying the tax rate to the taxable base for the period, after allowable deductions have been made, plus any changes in deferred tax assets and liabilities and tax credits, both for tax losses and deductions. Differences between the book value and tax basis of assets and liabilities generate deferred tax asset and liability balances, which are calculated using tax rates expected to be in effect when the assets and liabilities are realized or settled.

Current taxes and changes in deferred tax assets and liabilities not arising from business combinations are recorded in income or in equity in the statement of financial position, based on where the gains or losses originating them were recorded.

Deferred tax assets and tax credits are recognized only when it is likely that future tax gains will be sufficient to recover deductions for temporary differences and make use of tax credits.

Deferred tax liabilities are recognized for all temporary differences, except those derived from the initial recognition of goodwill and those that arose from valuing investments in subsidiaries, associates and jointly-controlled companies in which the Group can control their reversal and where it is likely that they will not be reversed in the foreseeable future.

Any deductions that can be applied to current tax liabilities are credited to earnings within the line item “Income tax expenses,” except when doubts exist about their tax realization, in which case they are not recognized until they are effectively realized, or when they correspond to specific tax incentives, in which case they are recorded as grants.

At each accounting period close, the Company reviews the deferred taxes it has recorded, both assets and liabilities, in order to ensure they remain current and otherwise make any necessary corrections based on the results of this analysis.

Revenue and expense recognition

Revenues and expenses are recognized on an accrual basis.

Revenue is recognized when the gross inflow of economic benefits arising in the course of the Group’s ordinary activities in the period occurs, provided that this inflow of economic benefits results in an increase in total equity that is not related to contributions from equity participants and that these benefits can be measured reliably. Revenue is measured at the fair value of the consideration received or receivable that gives rise to the revenue.

Revenue associated with the rendering of services is only recognized if it can be estimated reliably, based on the stage of completion of the service rendered at the date of the statement of financial position.

The Group excludes from the revenue figure gross inflows of economic benefits it receives when it acts as an agent or commission agent on behalf of third parties, and only recognizes as revenue economic benefits received for its own account.

When goods or services are exchanged or swapped for goods or services of a similar nature, the exchange is not regarded as a revenue-generating transaction.

The Group records the net amount of non-financial asset purchase or sale contracts settled for the net amount of cash or through some other financial instruments. Contracts entered into and maintained for the purpose of receiving or delivering these non-financial assets are recognized on the basis of the contractual terms of the purchase, sale, or usage requirements expected by the entity.

Interest income (expense) is recognized at the effective interest rate applicable to the outstanding principal over the repayment period.

These criteria for recognizing revenues and expenses are applied throughout the Enersis Group’s lines of business.

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Earnings per share

Basic earnings per share are calculated by dividing net income attributable to shareholders of Enersis (the numerator) by the weighted average number of ordinary shares outstanding (the denominator) during the period, excluding the average number of shares of the Parent Company held by the Group, if any.

During the 2012, 2011, and 2010 fiscal years, the Group did not engage in any transaction of any kind with potential dilutive effects leading to diluted earnings per share that could differ from basic earnings per share.

Dividends

Article 79 of the Chilean Companies Act establishes that, unless unanimously agreed otherwise by the shareholders of all issued shares, listed corporations must distribute a cash dividend to shareholders on a yearly basis, prorated by the shares owned or the proportion established in the company’s by-laws if there are preferred shares, of at least 30% of net income for each period, except when accumulated losses from prior years must be absorbed.

As it is practically impossible to achieve a unanimous agreement given Enersis’ highly fragmented share capital, as of the end of each period the amount of the dividend obligation to its shareholders is determined, net of interim dividends approved during the year, and then accounted for in “Trade and other current payables” or “Accounts payable to related companies,” as appropriate, and charged to Equity.

Interim and final dividends are deducted from Equity as soon as they are approved by the competent body, which in the first case is normally the Company’s Board of Directors and in the second case is the Ordinary Shareholders’ Meeting.

Systems of share-based remunerations

When Group employees take part in remuneration plans tied to the price of Enel stock, and the cost of the plan is borne by this company, the Group records the fair value of the Enel liability as an expense for employee benefits. At the same time, an increase is recorded to equity under Other Reserves for the same amount, representing Enel’s contribution (see Note 8.3).

Cash flow statements

The cash flow statement reflects the changes in cash that took place during the period, calculated using the direct method.

Cash flows: inflows and outflows of cash or cash equivalents, which are defined as highly liquid investments maturing in less than three months with a low risk of changes in value.

Operating activities: the principal revenue-producing activities of the Group and other activities that cannot be considered investing or financing activities.

Investment activities: the acquisition and disposal of long-term assets and other investments not included in cash and cash equivalents.

Financing activities: activities that result in changes in the size and composition of the total equity and borrowings of the Group.

4.	SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS

There are different regulations in the Latin American countries in which the Group operates. The main characteristics of each business are discussed below.

4.1

Generation:

Chile

In Chile, the electricity sector is regulated by the General Law of Electrical Services (Chilean Electricity Law), also known as DFL No. 1 of 1982, of the Ministry of Mining —whose compiled and coordinated text was established in DFL No. 4 issued in 2006 by the Ministry of Economy (the Electricity Law)— as well as by an associated Regulation (D.S. No. 327 issued in 1998). Three government bodies are primarily responsible for enforcing this law: the National Energy Commission (CNE), which has the authority to propose regulated tariffs (node prices) and to draw up indicative plans for the construction of new generating units; the Superintendency of Electricity and Fuels (SEF), which supervises and oversees compliance with the laws, regulations, and technical standards that govern the generation, transmission, and distribution of electricity, as well as liquid fuels, and gas;

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and, finally, the recently created Ministry of Energy, which will be responsible for proposing and guiding public policies on energy matters. It also oversees the SEF, the CNE, and the Chilean Commission for Nuclear Energy (ChCNE), thus strengthening coordination and allowing for an integrated view of the energy sector. The Ministry of Energy also includes the Agency for Energy Efficiency and the Center for Renewable Energy. The Chilean Electricity Law has also established a Panel of Experts whose main task is to resolve potential discrepancies among the players in the electricity market, including electricity companies, system operators, regulators, etc.

From a physical view point, the Chilean electrical sector is divided into four electrical grids: the Sistema Interconectado Central (SIC), the Sistema Interconectado del Norte Grande (SING), and two separate medium-size grids located in southern Chile, one in Aysén and the other in Magallanes. The SIC, the main electrical grid, runs 2,400 km longitudinally and connects the country from Taltal in the north to Quellon, on the island of Chiloe in the south. The SING covers the northern part of the country, from Arica down to Coloso, covering a length of some 700 km.

The electricity industry is organized into three business segments: generation, transmission, and distribution, all operating in an interconnected and coordinated manner, and whose main purpose is to supply electrical energy to the market at minimum cost while maintaining the quality and safety service standards required by the electrical regulations. Given their characteristics, the power transmission and distribution businesses are natural monopolies; these segments are regulated as such by the electricity law, which requires free access to networks and regulates rates.

Under the Chilean Electricity Law, companies engaged in generation and transmission on interconnected electrical grid must coordinate their operations through a centralizing operating agent, the Centro de Despacho Económico de Carga (CDEC), in order to operate the system at minimum cost while maintaining reliable service. For this reason, the CDEC plans and operates the system, including the calculation of the so-called “marginal cost,” which is the price assigned to CDEC-organized energy transfers occurring among power generating companies.

Therefore, a company’s decision to generate electricity is subject to the CDEC’s operation plan. On the other hand, each company is free to decide whether to sell its energy to regulated or unregulated customers. Any surplus or deficit between a company’s sales to its customers and its energy supply is sold to, or purchased from, other generators at the spot market price.

A power generating company may have the following types of customers:

(i) Regulated customers: Those residential and commercial consumers and small and medium-size businesses with a connected capacity equal to or less than 500 kW located in the concession area of a distribution company. Customers that consume from 500 kW to 2000 kW may choose to be regulated or unregulated clients. Until 2009, the transfer prices between generators and distribution companies were capped at a maximum value called the node price, which is regulated by the Ministry of Energy. Node prices are set every six months, in April and October, based on a report prepared by the CNE that takes into account projections of expected marginal costs in the system over the next 48 months for the SIC and 24 months for the SING. Beginning in 2010, and as the node price contracts begin to expire, the transfer prices between generators and distributors will be replaced by the results of regulated bidding processes, with a price cap set by the authority every six months.

(ii) Unregulated customers: Those customers, mainly industrial and mining companies, with a connected capacity of over 2,000 kW. These consumers can freely negotiate prices for electrical supply with generators and/or distributors. Customers with capacity between 500 and 2,000 kW, as indicated in the preceding paragraph, have the option to contract energy at prices agreed upon with their suppliers or be subject to regulated prices, with a minimum stay of at least four years under each pricing system.

(iii) Spot market: This represents energy and capacity transactions among generating companies that result from the CDEC’s coordination to keep the system running as economically as possible, where the surpluses (deficits) between a generator’s energy supply and the energy it needs to comply with business commitments are transferred through sales (purchases) to (from) other generators in the CDEC. In the case of energy, transfers are valued at the marginal cost, while node prices for capacity are set every semester by the regulators.

In Chile, the capacity that must be paid to each generator depends on an annual calculation performed by the CDEC to determine the firm capacity of each power plant, which is not the same as the dispatched capacity.

Beginning in 2010 with the enactment of Law 20,018, distribution companies must have enough supply permanently available to cover their entire demand projected for a period of three years; to do so, they must carry out long-term public bidding processes.

Regarding renewable energy, in April of 2008 Law 20,257 was enacted, which encourages the use of Non-Conventional Renewable Energies (NCRE). The principal aspect of this law is that at least 5% of generators’ energy sold to its customers should come from renewable sources between years 2010 and 2014. This requirement progressively increases by 0.5% from year 2015 until 2024, when a 10% renewable energy requirement will be reached.

On December 31, 2012, the Regulations containing the provisions governing complementary services were published in the Diario Oficial (the Official Gazette). These services are understood to be the technical resources in generation, transmission and distribution, and customer facilities that are not subject to price regulations and that each electrical system must have for the coordination of its operations as stipulated in Article 137 of the General Law on Electrical Services.

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The rest of Latin America

In the other Latin American countries where the Group operates, different regulations are enforced. In general, regulations in Brazil, Argentina, Peru, and Colombia allow participation of private capital in the electricity sector, uphold free competition in electricity generation, and define criteria to avoid certain levels of economic concentration and/or market practices that may cause a decline in this activity. Unlike Chile, state-owned companies participate in the electricity sector together with private companies in electricity generation, transmission, and distribution activities. Argentina began to show signs of intervening in the electricity market in 2002. This intervention became more marked in 2012, when the government informed companies in the electric industry of the general guidelines for restructuring the market, which will put an end to the marginalist system established in the 1990’s. The most significant changes should occur in the power generation sector.

In principle, all of these countries allow companies to participate in different activities (generation, distribution, and commercial), as long as these activities are properly separated both from an accounting and corporate point of view. Nevertheless, the transmission sector is where the strictest restrictions are usually imposed, mainly due to its nature and the need to assure adequate access to all players.

In regards to the main characteristics of the electricity generation business, it can be said that in general, these are open markets in which private players are free to make their own investment decisions. The exceptions are: Brazil, a country which, based on the contractual needs of the distribution companies, the Ministry of Energy actively participates in the electricity system’s expansion by establishing capacity quotas by technology (separate bids for thermal, hydraulic, or renewable energies) or participates directly by organizing public bids for specific projects; and Argentina where, despite the government’s promotion of initiatives to encourage electricity investments, such as “Energía Plus,” installed capacity has not increased as much as expected. This has led the government to develop a new monopolistic or oligopolistic direct regulation model it calls “Costo Plus” (Cost Plus) and has the following “declared principles”: i) An income will be applied to each company based on the sum of its net equity and financial debt, subtracting redundant assets; ii) “Reasonable profits” will be recognized; and iii) Efficient operating costs will be recognized.

In addition, operations in these countries are centrally coordinated, with an independent operator coordinating load dispatch. Except for Colombia, where dispatch is based on prices offered by the players, in the other countries load dispatched is centralized, based on variable production costs in order to ensure the fulfillment of the demand at a minimum cost for the system. From that dispatch, the marginal cost, which defines the price for spot transactions, is determined.

Nevertheless, in Argentina and Peru there is currently some level of intervention in setting prices in these marginal generation markets. This has occurred in Argentina since the 2002 crisis and also in Peru as a result of a recent Emergency Law enacted in 2008 and expected to be in force until 2015, which defines an idealized marginal cost, considering that the present restrictions do not exist for the gas and electricity transportation system.

In Colombia, Brazil, Peru, and Argentina, generation players are able to sell energy through contracts in the regulated or unregulated markets, and to trade their surplus/deficit on the spot market. The unregulated market is focused on the segment of large users, although the limits that define this status vary in each market. The principal differences among the markets involve how energy sales are regulated among generators and distributors and how regulated prices are established for the determination of the tariffs charged to end users. In Argentina, however, with the changes that are taking place in the generation sector, it is unclear what the generating companies’ role as sellers will be.

In Brazil, the regulated purchase price used in the determination of tariffs to end users is based on average prices of open bids, and there are separate bidding processes for existing and new energy. Bidding processes for new energy contemplate long-term generation contracts in which new generation projects must cover the growth of demand foreseen by distributors. The open bids for existing energy consider shorter contractual terms and seek to cover the distributors’ contractual needs arising from the expiry of prior contracts. Each bidding process is coordinated centrally. Authorities set maximum prices and, as a result, contracts are signed where all distributors participating in the process buy pro rata from each offering generator.

In Colombia, distributors are free to decide their supply, being able to define the conditions of public bidding processes where they acquire energy for the regulated market, and they are able to buy energy on the spot market. Prices paid by end users reflect an average of the purchase price. Since 2004, the CREG (the Colombian Energy and Gas Regulation Commission) is working on a proposal to modify the energy contracting system in the Colombian market. Under the proposal, the existing contracting system will be modified into an electronic contract system. This mechanism will replace the current bidding process for energy auctions with standardized commercial conditions, where contractual demand will be treated as a single aggregate demand.

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In Peru, as in Chile, distributors are obligated to enter into contracts, and the legislation was amended so that public bids for energy would be based on distributor requirements. Currently, there are only a few contracts between generators and distributors that are in force at “bar price” (the equivalent of the node price in Chile), which is set on the basis of centralized calculations. However, since 2007 contracts are based on public bids. Authorities approve the terms and conditions for the bidding and set the maximum price for each bid.

All of these countries have some regulations in force promoting the use of renewable energy. However, Chile is the only country that has established a mandatory quota for incorporating this type of technology.

4.2

Distribution:

General aspects

In the five countries where the Group operates, selling prices charged to clients are based on the purchase price paid to generators plus a component associated with the value added in distribution. Regulators set this value periodically through reviews of distribution tariffs. As a result, distribution is essentially a regulated activity.

Chile

In Chile, the Distribution Value Added (VAD) is established every four years. For this, the local regulator, (i.e. the CNE) classifies companies by typical areas that group together companies with similar distribution costs. A distribution company’s return on investment depends on the company’s performance compared to model company standards defined by the regulator. In April 2009, the regulator published tariff formulas which are effective for the period November 2008 through November 2012. In 2012 the Study process was initiated for calculating the components of the Distribution Value Added for the next tariff period, namely 2012-2016. On September 3, 2012 Chilectra handed the study in to the CNE; its results count for 1/3 of the value of the new tariffs, and the remaining 2/3 corresponds to the contribution made by the study carried out by the CNE.

On September 28, 2012, the CNE assigned the corresponding weighting to the 2 studies and published the preliminary basic tariffs, with which a check was made that the aggregate return on investment for the industry was within the established range of 10% with a dispersion of ± 4%. At December 2012 the tariff Decree was in the process of being officially recorded at the office of the Comptroller General of the Chilean Republic (Contraloría General de la República). Tariffs will have a retroactive effect from November 4, 2012 and will remain in force until November 3, 2016.

The rest of Latin America

Similarly, in Peru, the VAD is calculated every 4 years, also using a model company method based on a typical area. The tariffs for the 2009-2013 period were published in October 2009.

In Brazil, there are three types of tariff adjustments: i) Ordinary Tariff Reviews (ORT), which are conducted periodically in accordance with the provisions in the concession contracts (in Coelce every 4 years and in Ampla every 5 years); (ii) Annual adjustment (IRT); and (iii) Extraordinary Reviews.

At the end of 2011, the ANEEL regulating agency issued the modifications to the tariff calculation methods used for the third round of periodic reviews; one of the major changes is the decrease in the WACC. The most recent annual adjustments made by ANEEL were in March 2012 for Ampla and in April 2012 for Coelce.

The latest ORT revision for Ampla is applicable for the 2009-2013 periods and for Coelce for the 2007-2014 period. Coelce’s ORT for the 2011-2014 period, based on the new tariff methodology for the third round, was applied starting on April 22, 2012 and was calculated retroactively to April 2011. The Resolution requiring the annual readjustment also included the results of the Ordinary Tariff Review.

In Colombia, the Comisión de Regulación de Energía y Gas – the CREG – established in 2008 a new methodology for calculating the rate of return applicable to compensation for distribution, set a new value for that rate, and issued a new methodology for establishing the charges for regional transmission and local distribution systems use. In October 2009, the CREG published the distribution charges for Codensa, which will be in effect until October 2013 or until the Commission approves new charges. In 2011, the CREG carried out a study of the productivity index of the sales industry and issued the final resolutions of the Sales Regulations and loss management plans. In 2012, the CREG established annual low-voltage loss indexes that will be recognized in Codensa’s rates over the next five years.

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In Argentina, tariffs were frozen after the country’s debt default in 2001. Edesur’s tariff restructuring started in 2007 with the enforcement of the “Acta Acuerdo.” Starting in that year, tariff adjustments (positive impact in the VAD) and inflation readjustments (via the cost monitoring mechanism, MMC) were made. The last adjustment through the application of the MMC was for May-October 2007, and MMC adjustments not transferred to tariffs for subsequent periods remain pending to date. In July 2008 increases were authorized for clients with consumption in excess of 650 kWh quarterly, and in October 2008 the government approved an increase for consumption in excess of 1,000kWh per month; this last increase is a pass-through to the generators and was suspended between June and September 2010 but restarted in October 2010. During the first few months of 2010, Edesur submitted the rate charts applying Resolution 467/08 and the complementary information requested by the ENRE. At the end of 2011, the Government announced a reduction in state subsidies, and a seasonal price increase was established for customers in certain businesses and industries, as well as for some residential customer segments in specific geographic areas. At the end of 2012, the ENRE established a fixed charge on invoices differentiating among different categories of customers. This charge will set up a trust to finance infrastructure works and corrective maintenance that will be funded by the credits and debits determined by the regulating agency when it performs the IRT (the Revisión Tarifaria Integral, Comprehensive Tariff Review or annual rate adjustment). At the time of these financial statements, the IRT included in the Concession Contract Renegotiation Agreement remained pending.

Market for unregulated customers

In the countries where the Group operates, distributors can supply their customers under a regulated or freely agreed conditions. The supply limitations imposed on the unregulated market are as follows.


Country		kW threshold
Argentina		> 30 kW
Brazil		> 3,000 kW or > 500 kW (**)
Chile		> 500 kW
Colombia		> 100 kW or 55 MWh-month
Peru		> 200 kW (*)

(*). In April 2009, Peru established that clients between 200 and 2,500 kW could choose between the regulated and unregulated markets. Those over 2,500 kW are required to be unregulated customers.

(**) In Brazil, the > 500 kW limit applies if energy is purchased from renewable sources, for which the government provides incentives through a discount on tolls.

Limits on integration and concentration

In general, current legislation defends free competition and defines criteria to avoid certain levels of economic concentration and/or market practices that would lead to a deterioration of the market.

In principle, the regulators allow the participation of companies in different activities (e.g. generation, distribution, and commercialization) as long as there is an adequate separation of each activity, for both accounting and company purposes. Nevertheless, most of the restrictions imposed involve the transport sector mainly because of its nature and the need to guarantee adequate access to all agents. In Argentina and Colombia there are specific restrictions if generation or distribution companies want to become majority shareholders in transportation companies.

Additionally, in Colombia, companies that were created after 1994 may only engage in activities that are complementary to generation-sales and distribution-sales. Generation companies cannot hold an interest of over 25% in a distribution company and vice versa. Moreover, companies in Peru need a permit from the local authority if they have an ownership interest of more than 5% in one business activity and wish to take an ownership stake in a company in another business activity.

Regarding concentration in a specific sector, in Argentina, there are no specific limits that affect the vertical or horizontal integration of a company. In Chile, while there are regulations on free competition, there are no specific quantitative limits on vertical or horizontal integration. However, the General Law on Electrical Services provides that companies that operate on or have ownership in the Trunk Transmission Systems cannot engage in, either directly or indirectly, activities that are in any way involved in the business of power generation or distribution. In Peru, integrations are subject to authorization if such integration is 5% vertical and 15% horizontal. In Colombia, no company may have a direct or indirect market share of over 25% in electricity sale activities. Finally, in Brazil, with the changes taking place in the power industry under Law 10,848/2004 and Decree 5,163/2004, the ANEEL gradually perfected regulations, eliminating concentration limits as no longer compatible with the prevailing regulatory environment.

With regard to consolidations and mergers between agents of the same segment, current regulation requires authorization from the local regulator.

F-41

Access to the grid

In the countries where the Group operates, the right of access and toll or access price is regulated by the local authority.

In Peru, the toll-setting process that recognizes investments in Secondary and Complementary Transmission Systems for the period July 2006 through April 2013, and which are effective starting November 1, 2009, was concluded back in 2009.

In Chile, during 2010, local authorities developed part of the tariff process for determining the Subtransmission System’s Annual Value for the period 2011 through 2014. The CNE published the final technical report on May 13, 2011. Chilectra presented its discrepancies to the Panel of Experts in June of 2011, and the Panel of Experts issued its ruling on August 8. The CNE incorporated this ruling and drew up a final technical report on 26 October, which the Ministry of Energy will use to publish its subtransmission tariff decree. The decree is expected to be sent to the Governmental Controlling entity for registration and publication early in 2013. The tariffs it contains will be retroactive to January 1, 2011 and will be in effect until December 31, 2014.

5.	CASH AND CASH EQUIVALENTS

The detail of cash and cash equivalents as of December 31, 2012, 2011, and 2010 is as follows:


Cash and Cash Equivalents	Balance at
	12-31-2012		12-31-2011		12-31-2010
	ThCh$		ThCh$		ThCh$
Cash balances		16,948,408		1,287,851		279,960
Bank balances		331,157,493		269,065,858		186,975,512
Time deposits		356,138,051		398,152,529		518,742,837
Other fixed-income instruments		153,136,066		551,415,030		255,356,728
Total		857,380,018		1,219,921,268		961,355,037

Short-term time deposits have a maturity of three months or less from their date of acquisition and accrue the market interest for this type of investments. Other fixed-income investments are mainly comprised of resale agreements maturing in 30 days or less. There are no amounts of cash and cash equivalents balances held by the Group that are not available for its use.

The detail of cash and cash equivalents by currency is as follows:


Currency	12-31-2012		12-31-2011		12-31-2010
Currency	ThCh$		ThCh$		ThCh$
Chilean peso		226,886,433		535,594,942		322,190,328
Argentine peso		14,179,164		27,058,157		45,357,753
Colombian peso		320,331,513		268,199,899		150,964,209
Brazilian real		195,713,686		278,155,164		309,896,646
Peruvian sol		58,875,208		38,902,348		39,467,666
U.S. dollar		41,394,014		72,010,758		93,478,435
Total		857,380,018		1,219,921,268		961,355,037

following table shows the amounts received from the disposal of subsidiaries:


Disposal of Subsidiaries	12-31-2012		12-31-2011			12-31-2010
Disposal of Subsidiaries	ThCh$		ThCh$			ThCh$
Inflow received for disposals in cash and cash equivalents		-		31,486,668			-
Inflow of cash and cash equivalents in entities disposed of		-		(18,824,434	)		-
Assets and liabilities other than cash and cash equivalents in entities disposed of		-		(21,311,336	)		-
*Total consideration received for disposals ()**		-		(8,649,102	)		-

(*) See Note 2.4.1.

F-42

6.	OTHER FINANCIAL ASSETS

The detail of other financial assets as of December 31, 2012 and 2011 is as follows:


Other Financial Assets	Balance at
	Current				Non-current
	12-31-2012		12-31-2011		12-31-2012		12-31-2011
	ThCh$		ThCh$		ThCh$		ThCh$

Available-for-sale financial investments – unquoted equity securities or with limited liquidity		-		-		2,851,324		2,805,803
Available-for-sale financial investments – quoted equity securities		-		-		31,468		86,852
Available-for-sale financial investments IFRIC 12 () (*)		-		-		375,227,434
Financial assets held to maturity		-		-		27,045,746		20,793,960
Hedging derivatives (*)		51,876		748,078		32,384,466		12,178,355
Financial assets at fair value with change in net income (*)		194,196,327		-		-		-
Non-hedging derivatives (*)		-		47,504		-		-
Other assets		252,595		143,638		1,575,479		1,490,091

Total		194,500,798		939,220		439,115,917		37,355,061

(*) See Note 20.1.a.

(**) On September 11, 2012, the Brazilian government issued Temporary Law 579, which became permanent on January 13, 2013 and directly affects companies holding electric power generation, transmission, and distribution concessions, including Ampla and Coelce. Among its provisions, this legislation establishes that the government, as concession grantor, will use the Valor Nuevo de Reemplazo (VNR, New Replacement Value) to make the corresponding payments to the concessionaires for those assets that have not been amortized at the end of the concession period.

As a result of this new development, the subsidiaries have changed how they value and classify the amounts they expect to recover in compensation when the concession period ends. The previous approach was based on the past cost of the investments, and the rights to compensation were recorded as an account receivable. Now, however, they are valued on the basis of the VNR, and the compensation rights are classified as financial investments available for sale (see Notes 3.g, 6 and 7). Therefore, at the end of this fiscal year, a new estimate was made of the amounts Ampla and Coelce expect to receive at the end of the concession period, and ThCh$ 112,274,835 was entered as an increase to assets and financial income (see Note 31).

7.	TRADE AND OTHER RECEIVABLES

The detail of trade and other receivables as of December 31, 2012 and 2011 is as follows:

Trade and Other Receivables, Gross

Balance at

12-31-2012

12-31-2011

Current

Non-current

Current

Non-current

ThCh$

Trade and other receivables, gross

1,032,346,845

202,977,693

1,166,221,729

444,327,960

Trade receivables, gross

902,109,285

163,265,685

1,064,989,760

182,387,693

Other receivables, gross

130,237,560

39,712,008

101,231,969

261,940,267

Trade and Other Receivables, Net

Balance at

12-31-2012

12-31-2011

Current

Non-current

Current

Non-current

ThCh$

Trade and other receivables, net

869,204,566

202,977,693

977,602,388

443,328,450

Trade receivables, net

751,946,915

163,265,685

877,696,508

181,388,183

Other receivables, net (1)

117,257,651

39,712,008

99,905,880

261,940,267

(1) Includes mainly accounts receivable from personnel for ThCh$ 29,607,762 (ThCh$ 20,411,550 as of December 2011); accounts receivable from losses due to the earthquake and other indemnities to be received for ThCh$ 74,873,533 (ThCh$ 24,261,059 as of December 2011); and accounts receivable from Atacama Finance for ThCh$ 6,717,268 (ThCh$ 10,859,686 as of December 2011). Accounts receivable from the application of IFRIC 12, “Service Concession Agreements,” which as of December 2011 amounted to ThCh$ 212,947,609, were classified as available-for-sale financial investments at December 2012 (see Note 6).

F-43

There are no significant trade and other receivables balances held by the Group that are not available for its use.

The Group does not have clients to which it has sales representing 10% or more of its operating income in the periods ended December 31, 2012 and 2011.

Refer to Note 8.1 for detailed information on amounts, terms, and conditions associated with accounts receivable from related companies.

As of December 31, 2012 and 2011, the balance of unimpaired past due trade receivables is as follows:


Trade receivables past due but not impaired	Balance at
	12-31-2012		12-31-2011
	ThCh$		ThCh$
Less than three months		129,206,102		81,387,613
Between three and six months		11,822,289		38,450,793
Between six and twelve months		22,832,886		30,144,689
More than twelve months		123,065,090		114,487,265
Total		286,926,367		264,470,360

The reconciliation of changes in the allowance for impairment of trade receivables is as follows:


Trade receivables past due and unimpaired	Current and Non-current ThCh$

Balance at January 1, 2011		194,759,159
Increases (decreases) for the year (*)		18,649,480
Amounts written off		(7,046,353	)
Foreign currency translation differences		(16,743,435	)
Balance at December 31, 2011		189,618,851
Increases (decreases) for the year (*)		33,173,360
Amounts written off		(28,552,888	)
Foreign currency translation differences		(31,097,044	)
Balance at December 31, 2012		163,142,279

(*) See Note 28 for Impairment of financial assets.

Write-offs for bad debt

Past-due debt is written off once all collection measures and legal proceedings have been exhausted and the debtors’ insolvency has been demonstrated. In our power generation business, this process normally takes at least one year of procedures for the few cases that arise in each country. In our distribution business, considering the differences in each country, the process takes at least six months in Argentina and Brazil, 12 months in Colombia and Peru, and 24 months in Chile. Overall, the risk of bad debt, and therefore the risk of writing off our customers, is limited (see Notes 3.e and 19.5).

d) Additional information:

Additional statistical information required under Official Bulletin 715 of February 3, 2012, XBRL Taxonomy: see Appendix 6.

Complementary information on Trade Receivables, see Appendix 6.1.

F-44

8.	BALANCES AND TRANSACTIONS WITH RELATED PARTIES

Related party transactions are performed at current market conditions.

Transactions between the Company and its subsidiaries and joint ventures have been eliminated on consolidation and are not itemized in this note.

As of the date of these financial statements, no guarantees have been given or received nor has any allowance for bad or doubtful accounts been recorded with respect to receivable balances for related party transactions.

Enersis’ controlling shareholder is Endesa S.A., a Spanish corporation which, in turn, is controlled by the Italian corporation Enel S.p.A.

8.1

Balances and transactions with related companies

The balances of accounts receivable and payable between the Company and its non-consolidated related companies are as follows:

Receivables from related companies

Balance at

Current

Non-current

Taxpayer ID

No. (RUT)

Company

Country

Nature of
Relationship

Currency

Description of

Transaction

Term of
Transaction

12-31-2012

ThCh$

12-31-2011

ThCh$

12-31-2012

ThCh$

12-31-2011

ThCh$

Foreign

Empresa Eléctrica de Piura

Peru

Common Immediate Parent

Sol

Other services

Less than 90 days

34,666

208,118

Foreign

Endesa Energía S.A.

Spain

Common Immediate Parent

Other services

Less than 90 days

43,591

30,857

Foreign

Endesa Latinoamérica S.A.U.

Spain

Related to Immediate Parent

US$

Reimbursement for expenses

Less than 90 days

26,165

Foreign

Endesa S.A.

Spain

Related to Immediate Parent

US$

Other services

Less than 90 days

7,407

4,230

96,524,140-K

Empresa Electrica Panguipulli S.A.

Chile

Common Immediate Parent

CH$

Energy sales

Less than 90 days

22,457

107

96,880,800-1

Empresa Electrica Puyehue S.A.

Chile

Common Immediate Parent

CH$

Energy sales

Less than 90 days

95,399

Foreign

Generalima S.A.

Peru

Common Immediate Parent

CH$

Other services

Less than 90 days

23,890

311,013

Foreign

Generalima S.A.

Peru

Common Immediate Parent

Sol

Other services

Less than 90 days

578

Foreign

Endesa y Operaciones y Servicios Comerciales S.A. U.

Spain

Common Immediate Parent

Other services

Less than 90 days

71,721

Foreign

SACME S.A.

Argentina

Associate

Ar$

Other services

Less than 90 days

764,937

630,091

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Ar$

Energy sales

Less than 90 days

3,284,701

2,135,015

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Ar$

Tolls

Less than 90 days

20,286,684

21,546,570

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Ar$

Other

Less than 90 days

5,788,317

158,079

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Ar$

Other

Less than 90 days

16,724

76,788,080-4

GNL Quintero S.A.

Chile

Associate

CH$

Energy sales

Less than 90 days

771,985

76,788,080-4

GNL Quintero S.A.

Chile

Associate

CH$

Dividends and capital reduction

Less than 90 days

8,926,072

76,418,940-k

GNL Chile S.A.

Chile

Associate

US$

Other services

Less than 90 days

546,833

591,541

76,418,940-k

GNL Chile S.A.

Chile

Associate

CH$

Loans

Less than 90 days

379,802

379,862

Foreign

Endesa Generación S.A.U.

Spain

Common Immediate Parent

CH$

Commodity derivatives (*)

Less than 90 days

784,741

Foreign

Enel Ingegneria e Innovazione

Italy

Common Immediate Parent

CH$

Other services

Less than 90 days

36,340

Foreign

Central Dock Sud S.A.

Argentina

Common Immediate Parent

CH$

Other services

Less than 90 days

17,256

Foreign

PH Chucas Costa Rica

Costa Rica

Common Immediate Parent

CH$

Other services

Less than 90 days

42,019

317,563

Total

33,028,911

35,282,592

(*) See Note 20.3.

F-45

Payables to related companies

Balance at

Current

Non-current

Taxpayer ID

No. (RUT)

Company

Country

Nature of
Relationship

Currency

Description of

Transaction

Term of
Transaction

12-31-2012

ThCh$

12-31-2011

ThCh$

12-31-2012

ThCh$

12-31-2011

ThCh$

Foreign

Empresa Elétrica de Piura S.A.

Peru

Common Immediate Parent

Sol

Other services

Less than 90 days

162,847

995,885

Foreign

Endesa Latinoamérica S.A.

Spain

Related to Immediate Parent

Ar$

Dividends

Less than 90 days

105,569

130,841

Foreign

Endesa Latinoamérica S.A.

Spain

Related to Immediate Parent

CH$

Dividends

Less than 90 days

69,349,995

69,240,261

Foreign

Endesa Latinoamérica S.A.

Spain

Related to Immediate Parent

Dividends

Less than 90 days

17,925,206

27,306,717

Foreign

Endesa Latinoamérica S.A. (1)

Spain

Related to Immediate Parent

US$

Loans

More than one year

1,207,252

96,524,140-K

Empresa Electrica Panguipulli S.A.

Chile

Common Immediate Parent

CH$

Energy purchases

Less than 90 days

216,029

182,599

96,880,800-1

Empresa Electrica Puyehue S.A.

Chile

Common Immediate Parent

CH$

Energy purchases

Less than 90 days

15,896

60,659

Foreign

SACME

Argentina

Associate

Ar$

Other services

Less than 90 days

109,529

152,402

96,806,130-5

Electrogas S.A.

Chile

Associate

CH$

Other services

Less than 90 days

54,607

538,373

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Ar$

Fuel purchases

Less than 90 days

7,234,142

19,615,744

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Real

Energy transportation

Less than 90 days

20,595,952

21,546,571

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Ar$

Other services

Less than 90 days

3,081

Foreign

Endesa Cemsa S.A.

Argentina

Associate

CH$

Other services

Less than 90 days

752

68,039

76,418,940-k

GNL Chile S.A.

Chile

Associate

CH$

Natural gas purchases

Less than 90 days

25,884,955

8,517,317

Foreign

Carboex S.A.

Spain

Common Immediate Parent

CH$

Coal purchases

Less than 90 days

5,586,847

Foreign

Endesa Generación

Spain

Common Immediate Parent

CH$

Fuel purchases

Less than 90 days

4,556,927

Foreign

Endesa Generación

Spain

Common Immediate Parent

CH$

Commodity derivatives (*)

Less than 90 days

32,200

Foreign

Central Termica Manuel Belgrano

Argentina

Associate

Ar$

Mercantile Current Acct

Less than 90 days

846

Foreign

Enel Energy Europe S.L.U.

Spain

Common Immediate Parent

Other services

Less than 90 days

34,487

124,977

Foreign

Enel Energy Europe S.L.U.

Spain

Common Immediate Parent

CH$

Other services

Less than 90 days

373,944

1,613,683

Foreign

Enel Energy Europe S.L.U.

Spain

Common Immediate Parent

Euros

Other services

Less than 90 days

13,589

Foreign

Enel Energy Europe S.L.U.

Spain

Common Immediate Parent

Real

Other services

Less than 90 days

37,551

44,705

Foreign

Enel Energy Europe S.L.U.

Spain

Common Immediate Parent

Sol

Other services

Less than 90 days

48,086

Foreign

Enel Energy Europe S.L.U.

Spain

Common Immediate Parent

Ar$

Other services

Less than 90 days

7,402

Foreign

Enel Distribuzione

Italy

Ultimate Controlling Party

CH$

Other services

Less than 90 days

4,782

Foreign

Enel Produzione

Italy

Common Immediate Parent

CH$

Other services

Less than 90 days

80,928

Foreign

Central Dock Sud S.A.

Argentina

Common Immediate Parent

CH$

Other services

Less than 90 days

407

Foreign

Enel Green Power Mexico

Mexico

Common Immediate Parent

CH$

Other services

Less than 90 days

222,468

Total

146,827,411

157,177,638

(*) See Note 20.3.

(1)

The balance payable to Endesa Latinoamérica S.A. relates to a loan granted to Companhia Interconexao Energética S.A. (“CIEN”) to purchase machinery and equipment necessary to complete the construction of its second transmission line. The loan is denominated in US dollars, bears an annual interest rate of LIBOR + 2.73% and matures in May 2012.

F-46

Significant transactions and effects on income/expenses:

Transactions with non-consolidatable related companies and their effects on profit or loss are as follows:

12-31-2012

12-31-2011

12-31-2010

Taxpayer ID

No. (RUT)

Company

Country

Nature of
Relationship

Description of Transaction

Total
ThCh$

Foreign

Empresa Elétrica de Piura S.A.

Peru

Common Immediate Parent

Other operating income

47,905

57,534

162,670

Foreign

Empresa Elétrica de Piura S.A.

Peru

Common Immediate Parent

Other fixed operating expenses

(56,482)

Foreign

Empresa Elétrica de Piura S.A.

Peru

Common Immediate Parent

Energy purchases

(5,725,765)

(13,352,506)

(14,267,877)

Foreign

Empresa Elétrica de Piura S.A.

Peru

Common Immediate Parent

Other services rendered

233,512

210,546

191,034

Foreign

Empresa Elétrica de Piura S.A.

Peru

Common Immediate Parent

Energy sales

267,642

97,878

3,512

Foreign

Endesa Energía S.A.U.

Spain

Common Immediate Parent

Other operating income

50,410

48,844

39,585

Foreign

Endesa Latinoamérica S.A.U.

Spain

Immediate Parent

Interest on financial debt

(15,119)

118,904

(178,114)

Foreign

Endesa Latinoamérica S.A.

Spain

Immediate Parent

Other fixed operating expenses

(4,490)

Foreign

Endesa Servicios S.L.U.

Spain

Common Immediate Parent

Other services rendered

23,148

70,331

Foreign

Endesa Servicios S.L.U.

Spain

Common Immediate Parent

Other fixed operating expenses

(1,165)

(7,380)

Foreign

Endesa Servicios S.L.U.

Spain

Common Immediate Parent

Other operating income

75,041

127,091

Foreign

Endesa Generación

Spain

Common Immediate Parent

Fuel consumption

(41,522,504)

Foreign

Endesa Trading

Spain

Common Immediate Parent

Fuel consumption

(705,859)

Foreign

Eléctrica Cabo Blanco S.A.

Peru

Common Immediate Parent

Other services rendered

2,705

Foreign

Generalima S.A.

Peru

Common Immediate Parent

Other services rendered

23,890

598,940

395,480

76,418,940-k

GNL Chile S.A.

Chile

Associate

Natural gas consumption

(168,238,842)

(132,888,115)

(143,303,323)

76,418,940-k

GNL Chile S.A.

Chile

Associate

Natural gas transportation

(34,209,731)

(28,679,684)

(14,109,590)

76,418,940-k

GNL Chile S.A.

Chile

Associate

Other services rendered

220,493

39,006

76,418,940-k

GNL Chile S.A.

Chile

Associate

Other financial income

21,995

76,788,080-4

GNL Quintero S.A.

Chile

Associate

Energy sales

638,187

6,824,604

418,290

76,788,080-4

GNL Quintero S.A.

Chile

Associate

Other services rendered

661,296

86,563

96,976,600-0

Gestión Social S.A. (*)

Chile

Related to Director

Other services rendered

49,133

75,693

91,412

78,488,290-k

Tironi y Asociados S.A. (*)

Chile

Related to Director

Other services rendered

2,475

33,703

62,602

Foreign

SACME S.A.

Argentina

Associate

Outsourced services

(1,166,157)

(945,433)

(759,389)

96,880,800-1

Empresa Eléctrica Puyehue S.A.

Chile

Common Immediate Parent

Energy purchases

(1,988,042)

(2,277,414)

(1,919,788)

96,880,800-2

Empresa Eléctrica Puyehue S.A.

Chile

Common Immediate Parent

Energy sales

99,120

43,114

48,042

96,524,140-K

Empresa Eléctrica Panguipulli S.A.

Chile

Common Immediate Parent

Energy purchases

(789,477)

(3,813,927)

(3,554,055)

96,524,140-K

Empresa Eléctrica Panguipulli S.A.

Chile

Common Immediate Parent

Energy sales

133,735

131,038

8,876

Foreign

Enel S.A.

Italy

Ultimate Controlling Party

Other services rendered

175,358

Foreign

Enel Distribuzione

Italy

Ultimate Controlling Party

Other fixed operating expenses

(97,053)

Foreign

Enel Energy Europe

Spain

Common Immediate Parent

Other fixed operating expenses

(649,266)

Foreign

Enel Energy Europe

Spain

Common Immediate Parent

Other operating income

16,222

1,389,272

96,806,130-5

Electrogas S.A.

Chile

Associate

Natural gas tolls

(2,175,039)

(2,914,936)

(2,814,618)

96,806,130-5

Electrogas S.A.

Chile

Associate

Fuel consumption

(697,653)

Foreign

Carboex S.A.

Spain

Common Immediate Parent

Fuel consumption

(5,042,960)

(39,042,866)

Foreign

Central Térmica Manuel Belgrano

Argentina

Associate

Other financial income

286,516

Foreign

Central Térmica San Martin

Argentina

Associate

Other financial income

211,530

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Energy purchases

(3,474,994)

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Electricity tolls

(6,577)

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Other services rendered

3,474,747

Foreign

Endesa Cemsa S.A.

Argentina

Associate

Other fixed operating expenses

(801,990)

Foreign

Endesa y Operaciones y Servicios Comerciales S.A. U.

Spain

Common Immediate Parent

Other operating income

77,019

Foreign

ENEL Green Power Mexico

Mexico

Common Immediate Parent

Other services rendered

19,216

Foreign

PH Chucas Costa Rica

Costa Rica

Common Immediate Parent

Other services rendered

481,177

419,356

Foreign

Endesa Distribución Eléctrica S.L.U.

Spain

Common Immediate Parent

Other fixed operating expenses

(6,133)

Foreign

Enel Ingegneria e Innovazione

Italy

Common Immediate Parent

Other services rendered

30,536

76,583,350-8

Konecta Chile S.A.

Chile

Associate

Other variable expenses

(22,179)

76,583,350-7

Konecta Chile S.A.

Chile

Associate

Other services rendered

29,788

170,762

Total

(260,783,667)

(213,186,865)

(178,938,482)

Transfers of short-term funds between related companies are treated as current accounts changes, with variable interest rates based on market conditions used for the monthly balance. The resulting amounts receivable or payable are usually at 30 days term, with automatic rollover for the same term and amortization in line with cash flows.

(* ) Companies with a connection to Enersis Director Eugenio Tironi Barrios.

As of December 31, 2012, there is no balance pending payment to Sociedad Gestión Social S.A. At the end of the 2011 fiscal year, there was a balance payable of ThCh$ 4,119.

F-47

8.2 Board of Directors and key management personnel

Enersis is managed by Board of Directors which consists of seven members. Each director serves for a three-year term after which they can be reelected.

The Board of Directors was elected at the Ordinary Shareholders Meeting held on April 26, 2011. The Chairman, Vice Chairman, and Secretary were designated at the Board meeting held on April 27, 2011.

Accounts receivable and payable and other transactions

—

Accounts receivable and payable

There are no outstanding amounts receivable or payable between the Company and the members of the Board of Directors and key management personnel.

—

Other transactions

No other transactions have taken place between the Company and the members of the Board of Directors and key management personnel.

Compensation for Directors

In accordance with Article 33 of Law No. 18,046 governing stock corporations, the compensation of Directors is established each year at the Ordinary Shareholders Meeting of Enersis S.A.

The remuneration consists of paying a variable annual compensation equal to one one-thousandth of the profit for the year (attributable to Shareholders of Enersis). Also, each member of the Board will be paid a monthly compensation, one part a fixed monthly fee and another part dependent on meetings attended. The remuneration breaks down as follows:

-101 UF as a fixed monthly fee, and

-66 UF as per diem for each Board meeting attended.

The amounts paid for the monthly fee will be treated as payment in advance of the variable annual compensation described above. As stated in the by-laws, the remuneration for the Chairman of the Board will be twice that of a Director, and the compensation of the Vice Chairman will be 50% higher than that of a Director.

Any advance payments received will be deducted from the annual variable compensation, with no reimbursement if the annual variable compensation is lower than the total amount paid in advances. The variable compensation will be paid after the Ordinary Shareholders’ Meeting approves the Annual Report, Balance Sheet and Financial Statements, and the Independent Auditors’ Reports and Account Inspectors’ Reports for the year ending December 31, 2012.

If any Director of Enersis S.A. is a member of more than one Board in any Chilean or foreign subsidiaries and/or associates, or holds the position of director or advisor in other Chilean or foreign companies or legal entities in which Enersis S.A. has a direct or indirect ownership interest, that Director can be compensated for his/her participation in only one of those Boards.

The Executive Officers of Enersis S.A. and/or any of its Chilean or foreign subsidiaries or associates will not receive any compensation or per diem if they hold the position of director in any of the Chilean or foreign subsidiaries or associates of Enersis S.A. Nevertheless, the executives may receive such compensation or per diem provided it is authorized as payment in advance of the variable portion of their remuneration received from the respective companies by which the executives are employed.

Directors’ Committee:

Each member of the Directors’ Committee will receive a variable remuneration equal to 0.11765 thousandth of the profit for the year (attributable to shareholders of Enersis). Also each member will be paid a monthly compensation, one part in a fixed monthly fee and another part dependent on meetings attended.

This remuneration is broken down as follows:

38.00 UF as a fixed monthly fee, and

18.00 UF as per diem for each Board meeting attended.

The amounts paid for the monthly fee will be treated as payment in advance of the variable annual compensation described above.

F-48

The following tables show details of the compensation paid to the members of the Board of Directors as of December 31, 2012, 2011, and 2010.


					12-31-2012
Taxpayer ID No. (RUT)	Name	Position	Period in Position ThCh$	Enersis Board ThCh$	Board of Subsidiaries or Associates ThCh$	Directors’ Committee ThCh$	Auditing Committee ThCh$
5,710,967-K	Pablo Yrarrázaval Valdés	Chairman	January - December 2012	120,654	-	-		-
Foreign	Andrea Brentan (1)	Vice Chairman	January - December 2012	-	-	-		-
48,070,966-7	Rafael Miranda Robredo	Director	January - December 2012	60,327	-	-		-
5,719,922-9	Leónidas Vial Echeverría	Director	January - December 2012	60,734	-	18,479		-
6,429,250-1	Rafael Fernández Morandé	Director	January - December 2012	61,141	-	18,886		-
4,132,185-7	Hernán Somerville Senn	Director	January - December 2012	61,141	-	18,886		-
5,715,860-3	Eugenio Tironi Barrios	Director	January - December 2012	60,327	-	-		-


	TOTAL			424,324	-	56,251		-


					12-31-2011
Taxpayer ID No. (RUT)	Name	Position	Period in Position ThCh$	Enersis Board ThCh$	Board of Subsidiaries or Associates ThCh$	Directors’ Committee ThCh$	Auditing Committee ThCh$
5,710,967-K	Pablo Yrarrázaval Valdés	Chairman	January - December 2011	80,062	-	-		-
48,070,966-7	Rafael Miranda Robredo	Director	January - December 2011	39,256	-	-		-
5,719,922-9	Leonidas Vial Echeverría	Director	January - December 2011	40,031	-	13,018		-
6,429,250-1	Rafael Fernández Morandé	Director	January - December 2011	40,031	-	13,410		-
4,132,185-7	Hernán Somerville Senn	Director	January - December 2011	40,031	-	13,410		-
5,715,860-3	Eugenio Tironi Barrios	Director	January - December 2011	40,031	-	-		-


	TOTAL			279,442	-	39,838		-


					12-31-2010
Taxpayer ID No. (RUT)	Name	Position	Period in Position ThCh$	Enersis Board ThCh$	Board of Subsidiaries or Associates ThCh$	Directors’ Committee ThCh$	Auditing Committee ThCh$
5,710,967-K	Pablo Yrarrázaval Valdés	Chairman	January - December 2010	55,023	-	759		-
48,070,966-7	Rafael Miranda Robredo	Vice Chairman	January - December 2010	27,511	-	-		-
5,719,922-9	Leonidas Vial Echeverría	Director	April – December 2010	19,138	-	6,638		-
6,429,250-1	Rafael Fernández Morandé	Director	April – December 2010	19,138	-	6,638		-
4,132,185-7	Hernán Somerville Senn	Director	January - December 2010	26,743	-	8,665		1,520
5,715,860-3	Eugenio Tironi Barrios	Director	January - December 2010	26,750	-	764		-
5,206,994-7	Patricio Claro Grez	Director	January – April 2010	8,373	-	2,284		1,520


	TOTAL			182,676	-	25,748		3,040

(1) Mr. Andrea Brentan waived the fees and allowances due him as company Director.

F-49

Guarantees established by the Company in favor of the Directors

No guarantees have been given to the Directors.

8.3

Compensation for key management personnel

Compensation received by key management personnel


Key Management Personnel
Taxpayer ID No. (RUT)	Name	Position
22,298,662-1	Ignacio Antoñanzas Alvear	Chief Executive Officer
23,535,550-7	Massimo Tambosco	Deputy Chief Executive Officer
7,984,912-K	Eduardo Escaffi Johnson (1)	Chief Financial Officer
14,710,692-0	Angel Chocarro García	Accounting Officer
22,357,225-1	Ramiro Alfonsín Balza	Planning and Control Officer
Foreign	Alain Rosolino (2)	Internal Audit Officer
7,006,337-9	Francisco Silva Bafalluy	General Services Officer
11,470,853-4	Juan Pablo Larraín Medina	Communications Officer
23,014,537-7	Carlos Niño Forero	Human Resources and Organization Officer
7,706,387-0	Eduardo Lopez Miller	Procurement Officer
6,973,465-0	Domingo Valdés Prieto	General Counsel

(1) Mr. Eduardo Escaffi Johnson took over as Regional Finance Manager on September 1, 2012, replacing Mr. Alfredo Ergas S., who resigned on August 27, 2012.

(2) On December 12, 2012, Ms. Alba Marina Urrea G. voluntarily resigned from Enersis; Mr. Alain Rosolino was designated as her replacement on the same date.

Compensation received by key management personnel is the following:


	Balance at
	12-31-2012	12-31-2011	12-31-2010
	ThCh$	ThCh$	ThCh$

Cash Compensation	2,615,660	2,660,608	1,790,071
Short-term benefits for employees	996,474	846,340	817,101
Other long-term benefits	724,297	151,636	87,888

Total	4,336,431	3,658,584	2,695,060

Incentive plans for key management personnel

Enersis has implemented an annual bonus plan for its executives based on meeting company-wide objectives and on the level of their individual contribution in achieving the overall goals of the Group. The plan provides for a range of bonus amounts according to seniority level. The bonuses paid to the executives consist of a certain number of monthly gross remunerations.

Guarantees established by the Company in favor of key management personnel

No guarantees have been given to key management personnel.

F-50

8.4 Compensation plans linked to share price

There are no payment plans granted to the Directors or key management personnel based on the price of Enersis stock.

However, until the 2011 fiscal year, certain key Enersis personnel benefited from one of the Enel remuneration plans that is based on the price of its stock. The cost of this plan is borne by Enel and does not give rise to any payment obligations for Enersis. The main features of this plan are the following:

Restricted share units plan from 2008:

This plan is aimed at Enel Group executives, and its beneficiaries are divided into brackets. The basic number of units granted to each beneficiary was determined on the basis of the average gross annual compensation of the bracket, as well as the price of Enel shares at the start of the period covered by the plan (January 2, 2008). The right to exercise the units is subordinate to the condition that the executives concerned remain employed within the Group, with a few exceptions.

The plan establishes a suspensory operational objective (a “hurdle target”) as follows:

i) For the first 50% of the basic number of units granted, Group EBITDA for 2008-2009, calculated on the basis of the amounts specified in the budgets for those years.

ii) For the remaining 50% of the basic number of units granted, Group EBITDA for 2008-2010, calculated on the basis of the amounts specified in the budgets for those years.

If the hurdle target, as described above, is achieved, the actual number of units that can be exercised by each beneficiary is determined on the basis of a performance objective represented by:

i) For the first 50% of the basic number of units granted, a comparison on a total shareholders’ return basis – for the period from January 1, 2008 to December 31, 2009 – between the performance of ordinary Enel shares on the Italian stock exchange and that of a specific reference index.

ii) For the remaining 50% of the basic number of units granted, a comparison on a total shareholders’ return basis – for the period from January 1, 2008 to December 31, 2010 – between the performance of ordinary Enel shares on the Italian stock exchange and that of a specific reference index.

The number of units that can be exercised may vary up or down with respect to the basic unit granted by a percentage amount of between 0% and 120% as determined on the basis of a specific performance scale.

If the hurdle target is not achieved in the first two-year period, the first tranche of 50% of the units granted may be recovered if the same hurdle target is achieved over the longer three-year period indicated above. It is also possible to extend the validity of the performance level registered in the 2008-2010 period to the 2008-2009 period.

Depending on the degree to which both objectives are met, of the total number of units granted, 50% may be exercised from the second year subsequent to the year in which they were granted, and the remaining 50% as from the third year subsequent to the year in which they were granted. The deadline for exercising all the units is the sixth year subsequent to the year in which they were granted.

The following table summarizes the plan’s evolution.


	Number of restricted share units
Restricted units granted December 31, 2008		2,700
Restricted units expired in 2009		-
Restricted units pending at December 31, 2009		2,700
Restricted units expired in 2010		-
Restricted units exercised in 2010		-
Restricted units pending at December 31, 2010		2,700
Restricted units pending at January 1, 2011 (with a revaluation of 120%)		3,240
Restricted units exercised in the first half of 2011 *()**		3,240
Restricted units pending at December 31, 2011		-

(*) The fiscal year value of the restricted share units was €13,683 (2011).

Using the accounting criterion described in Note 3.s, Enersis simultaneously recognized a personnel expense and an equity increase for €1,614 (2011). This amount corresponds to the accrued value during the period in which key personnel involved in this plan provided services to Enersis.

F-51

9.	INVENTORIES

The detail of inventories as of December 31, 2012 and 2011 is as follows:


Classes of Inventories	Balance at
Classes of Inventories	12-31-2012		12-31-2011
	ThCh$		ThCh$

Goods		5,010,620	2,575,623
Supplies for production		42,462,327	35,893,349
Other inventories (*)		36,006,546	39,456,572

Total		83,479,493	77,925,544

Detail of other inventories
*() Other inventories**		36,006,546	39,456,572
Supplies for projects and spare parts		26,705,519	26,562,119
Electric supplies		9,301,027	12,894,453

There are no inventories pledged as security for liabilities.

For the Period ended December 31, 2012, the figure for raw materials and supplies recognized as an expense was ThCh$ 782,263,736 (ThCh$ 742,639,363 and ThCh$ 672,038,103 at December 31, 2011 and 2010, respectively). See Note 26.

As of December 31, 2012, 2011, and 2010, no inventories have been written down.

10.

TAX RECEIVABLES AND PAYABLES

The detail of current tax receivables as of December 31, 2012 and 2011 is as follows:


Tax Receivables	Balance at
	12-31-2012		12-31-2011
	ThCh$		ThCh$

Monthly provisional tax payments		62,785,901	84,429,230
VAT tax credit		74,704,027	39,192,265
Tax credit for absorbed profits		60,335,643	8,067,408
Tax credit for training expenses		235,498	7,040
Other		12,943,811	10,131,741

Total		211,004,880	141,827,684

The detail of current tax payables as of December 31, 2012 and 2011 is as follows:


Tax Payables	Balance at
	12-31-2012		12-31-2011
	ThCh$		ThCh$

Income tax		81,236,746	110,516,971
VAT tax charge		22,271,681	45,054,989
Other		69,628,283	80,281,282

Total		173,136,710	235,853,242

F-52

11.

NON-CURRENT ASSETS AND DISPOSAL GROUPS HELD FOR SALE

During the fourth quarter of 2009, the Board of Directors of Enersis authorized the sale of the subsidiaries Compañía Americana de Multiservicios (CAM) and Synapsis Soluciones y Servicios IT Ltda. (Synapsis), as they were considered “non-core” businesses. The sale process included at first an internal verification of the market and the hiring of financial advisors to provide assistance in the sale process. Once offers were received, they were submitted to the Board so that it could make the final decision about the sale and its specific conditions.

The potential sale of CAM was considered to be highly probable as of the end of 2009. As for Synapsis, such consideration was taken into account as of September 2010. After those dates, the Company applied IFRS 5 Non-current Assets Held for Sale and Discontinued Operations (IFRS 5) to account for these transactions.

CAM and Synapsis provide services in the five countries where Enersis operates in Latin America, i.e. Chile, Argentina, Brazil, Colombia, and Peru. CAM is present with its products and services throughout the electric cycle, including provision, materials logistics, construction and startup of electric projects, certification of equipment, and measurement of final consumption. Furthermore, Synapsis is a company that provides information technology services. It specializes in defining strategies companies can use and helping them select software that satisfies their business needs. Synapsis also designs the infrastructure of the services that will be provided and the methodology to be used, as well as other services.

On December 20, 2010, the Board of Directors of Enersis accepted the offers received to purchase its entire interests in CAM and Synapsis. The CAM offer was presented by Graña y Montero S.A.A., a Peruvian company that offered US$20 million, an amount which, after a price adjustment and contractual compensations, was reduced to US$14.2 million. As for Synapsis, Riverwood Capital L.P., a company domiciled in the United States of America, presented a US$52 million offer to purchase Synapsis, which will be paid upon the closing of the sales transaction. The sale of CAM was closed on February 24, 2011, and the Synapsis sale was finalized on March 1, 2011 (see Note 2.4.1).

As described in Note 3 j), non-current assets and disposal groups held for sale have been recorded at the lower of book value or fair value less selling costs. The impact of this treatment was to record an additional impairment on CAM’s net assets as of December 31, 2010 in the amount of ThCh$ 14,881,960, which accumulates to a total impairment of ThCh$ 36,797,809 related to CAM as of December 31, 2010 (ThCh$ 21,915,849 as of December 31, 2009), which was calculated based on the sales price received.

F-53

12.

INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD AND JOINT VENTURES

12.1

Investments accounted for using the equity method

The following tables present the changes in shareholders’ equity of the Group’s equity method investments during the 2012 and 2011 fiscal years:


Taxpayer ID No. (RUT)	Changes in Investments in Associates	Country	Functional Currency	Ownership Interest		Balance at 01/01/2012 ThCh$		Share of Profit (Loss) ThCh$		Dividends Declared ThCh$		Foreign Currency Translation ThCh$		Other Comprehensive Income ThCh$		Balance at 12-31-2012 ThCh$		Negative Equity Provision (2)		Balance at 12-31-2012

96,806,130-5	Electrogas S.A. (1)	Chile	U.S. dollar		42.50%		9,733,400		4,283,023		(4,186,063)		(761,847)		(38,072)		9,030,441		-	9,030,441
76,788,080-4	GNL Quintero S.A.	Chile	U.S. dollar		20.00%		-		5,198,419		(2,738,825)		644,605		782,465		3,886,664		(3,886,664)	-
76,418,940-K	GNL Chile S.A.	Chile	U.S. dollar		33.33%		-		388,865		-		(5,373)		(6,657)		376,835		-	376,835
Foreign	Endesa Cemsa S.A.	Argentina	Argentine peso		45.00%		3,428,480		(24,718)		-		(660,005)		(32)		2,743,725		-	2,743,725
Foreign	Sacme S.A.	Argentina	Argentine peso		50.00%		31,382		313		-		(6,012)		-		25,683		-	25,683
					TOTAL		13,193,262		9,845,902		(6,924,888)		(788,632)		737,704		16,063,348		(3,886,664)	12,176,684

Taxpayer ID No, (RUT)	Changes in Investments in Associates	Country	Functional Currency	Ownership Interest		Balance at 01/01/2011 ThCh$		Share of Profit (Loss) ThCh$		Dividends Declared ThCh$		Foreign Currency Translation ThCh$		Other Comprehensive Income ThCh$		Balance at 12-31-2011 ThCh$		Negative Equity Provision		Balance at 12-31-2011

96,806,130-5	Electrogas S.A. (1)	Chile	U.S. dollar		42.50%		3,827		4,159,992		(4,142,727)		918,611		8,793,697		9,733,400		-	9,733,400
96,889,570-2	Inversiones Electrogas S.A.	Chile	Chilean peso		42.50%		8,089,685		-		-		-		(8,089,685)		-		-	-
76,788,080-4	GNL Quintero S.A.	Chile	U.S. dollar		20.00%		2,883,633		4,055,771		-		66,992		(15,880,240)		(8,873,844)		8,873,844	-
Foreign	Endesa Cemsa S.A.	Argentina	Argentine peso		45.00%		3,094,078		249,673		-		84,729		-		3,428,480		-	3,428,480
Foreign	Sacme S.A.	Argentina	Argentine peso		50.00%		30,151		468		-		763		-		31,382		-	31,382
76,583,350-7	Konecta Chile S.A.	Chile	Chilean peso		26.20%		278		-		-		-		(278)		-		-	-
					TOTAL		14,101,652		8,465,904		(4,142,727)		1,071,095		(15,176,506)		4,319,418		8,873,844	13,193,262

(1)

On November 16, 2011, the company Electrogas S.A. merged with the company Inversiones Electrogas S.A.

(2)

Represents partial reversal of negative equity provision recognized in 2011.

F-54

As of December 31, 2012 and 2011 no changes in ownership interest in our investment associates have occurred.

Additional financial information about investments in associates

- Investments with significant influence

The following tables show financial information as of December 31, 2012 and 2011 from the Financial Statements of the main investments in associates where the Group has significant influence:


	December 31, 2012
Investments with significant influence	Ownership interest %	Current assets ThCh$		Non-current assets ThCh$		Current liabilities ThCh$		Non-current liabilities ThCh$		Revenues ThCh$		Expenses ThCh$		Profit (Loss) ThCh$
Endesa Cemsa S.A.	45.00%		46,897,389		873,409		41,673,631		-		3,255,026		(3,309,953)	(54,927)
GNL Quintero S.A.	20.00%		72,284,363		541,694,388		27,968,039		610,947,052		101,634,665		(75,642,607)	25,992,058
Electrogas S.A.	42.50%		2,488,996		38,787,769		7,935,168		12,093,501		18,509,416		(8,431,715)	10,077,701


	December 31, 2011
Investments with significant influence	Ownership interest %	Current assets ThCh$		Non-current assets ThCh$		Current liabilities ThCh$		Non-current liabilities ThCh$		Revenues ThCh$		Expenses ThCh$		Profit (Loss) ThCh$
Endesa Cemsa S.A.	45.00%		49,705,466		820,787		42,907,410		-		3,423,785		(2,868,957)	554,828
GNL Quintero S.A.	20.00%		112,362,755		600,607,534		76,192,955		681,146,225		95,676,650		(75,397,751)	20,278,899
Electrogas S.A.	42.50%		2,688,608		44,772,738		9,510,888		15,048,487		17,218,630		(7,430,408)	9,788,222

Appendix 3 to these consolidated financial statements provides information on the main activities of our associate companies and the ownership interest the Group holds in them.

None of our associates have published price quotations.

12.2

Joint ventures

The following tables set out summarized information from the financial statements of the main joint ventures that are reported using proportional consolidation as of December 31, 2012 and 2011:


	December 31, 2012
	Ownership interest %	Current assets ThCh$		Non-current assets ThCh$		Current liabilities ThCh$		Non-current liabilities ThCh$		Revenues ThCh$		Expenses ThCh$		Profit (Loss) ThCh$
Hidroaysen S.A.	51.00%		10,081,574		127,061,491		5,728,373		248,465		-		(1,140,074)	(1,140,074)
Transmisora Eléctrica de Quillota Ltda.	50.00%		3,273,653		9,921,635		503,949		1,269,420		2,265,866		(1,576,437)	689,429
Gas Atacama S.A.	50.00%		109,901,311		280,273,935		48,808,533		42,927,589		119,376,455		(82,726,987)	36,649,468
Distribuidora Eléctrica de Cundinamarca S.A.	48.99%		23,345,306		108,830,580		32,149,721		69,636,889		78,544,480		(72,429,762)	6,114,718


	December 31, 2011
	Ownership interest %	Current assets ThCh$		Non-current assets ThCh$		Current liabilities ThCh$		Non-current liabilities ThCh$		Revenues ThCh$		Expenses ThCh$		Profit (Loss) ThCh$
Hidroaysen S.A.	51.00%		10,250,367		115,878,802		7,348,428		1,035,256		-		(4,664,851)	(4,664,851)
Transmisora Eléctrica de Quillota Ltda.	50.00%		1,463,786		10,533,846		298,164		966,978		2,310,668		(1,632,824)	677,844
Gas Atacama S.A.	50.00%		93,103,848		314,752,350		77,452,973		45,808,413		260,889,567		(225,125,891)	35,763,676
Distribuidora Eléctrica de Cundinamarca S.A.	48.99%		19,310,231		95,221,154		21,878,731		35,202,359		67,811,590		(61,233,568)	6,578,022

F-55

13.

INTANGIBLE ASSETS OTHER THAN GOODWILL

Intangible assets as of December 31, 2012 and 2011 are detailed as follows:


Intangible Assets, Net	12-31-2012		12-31-2011
Intangible Assets, Net	ThCh$		ThCh$

Intangible assets, net		1,203,135,574	1,467,398,214
Easements and water rights		44,658,323	33,716,526
Concessions, net (1) (*)		1,093,803,169	1,369,031,940
Development costs		10,310,522	10,282,488
Patents, registered trademarks, and other rights		2,546,806	2,363,933
Computer software		48,891,809	48,745,282
Other identifiable intangible assets		2,924,945	3,258,045

Intangible Assets, Gross	12-31-2012		12-31-2011
Intangible Assets, Gross	ThCh$		ThCh$

Intangible assets, gross		2,225,830,913	2,361,625,560
Easements and water rights		52,702,900	40,322,337
Concessions		1,970,550,917	2,145,097,304
Development costs		19,823,753	17,698,378
Patents, registered trademarks, and other rights		10,734,905	9,237,477
Computer software		159,737,005	139,315,361
Other identifiable intangible assets		12,281,433	9,954,703

Intangible Assets	12-31-2012		12-31-2011
Intangible Assets	ThCh$		ThCh$

Accumulated Amortization and Impairment, Total		(1,022,695,339)	(894,227,346)
Easements and water rights		(8,044,577)	(6,605,811)
Concessions		(876,747,748)	(776,065,364)
Development costs		(9,513,231)	(7,415,890)
Patents, registered trademarks, and other rights		(8,188,099)	(6,873,544)
Computer software		(110,845,196)	(90,570,079)
Other identifiable intangible assets		(9,356,488)	(6,696,658)

(1) The detail of concessions is the following:

Concession Holder

Country

Term of
Concession

Period to
Expiration

12-31-2012

ThCh$

12-31-2011

ThCh$

Concesionaria Túnel el Melon S.A. (Highway infrastructure)

Chile

23 years

5 years

10,049,562

12,152,979

Ampla Energía e Servicios S.A. (Distribution)

Brazil

30 years

15 years

625,413,669

733,283,981

Compañía Energetica do Ceara S.A. (Distribution)

Brazil

30 years

16 years

458,339,938

623,594,980

TOTAL

1,093,803,169

1,369,031,940

(*) See Note 3.d.1

During the 2012 fiscal year, the Brazilian regulatory agency changed the period in which it pays incentives for investments made in assets in electricity distribution concessions, which has resulted in a ThCh$ 108,639,110 decrease in the value of intangible assets recorded for the concession. This decrease has been offset by a similar increase in available-for-sale financial investments, as this change gives rise to a higher amount that can be recovered as payment for investments made, which will be recovered at the end of the concession period (see Note 6).

F-56

The reconciliation of the carrying amounts of intangible assets during the 2012 and 2011 fiscal years is as follows:

Year ended December 31, 2012


Changes in Intangible Assets	Development Costs, Net		Easements and Water Rights, Net			Concessions, Net			Patents, Registered Trademarks, and Other Rights, Net			Computer Software, Net			Other Identifiable Intangible Assets, Net			Intangible Assets, Net
Changes in Intangible Assets	ThCh$		ThCh$			ThCh$			ThCh$			ThCh$			ThCh$			ThCh$

Opening balance at 1-1-2012		10,282,488		33,716,526			1,369,031,940			2,363,933			48,745,282			3,258,045			1,467,398,214
Changes in identifiable intangible assets
Additions		4,077,641		1,049,888			149,026,486			666,661			23,273,818			25,162			178,119,656
Disposals		(1,104,668)		(5,016	)		(1,303,906	)		(1	)		(12,842	)		(6,835	)		(2,433,268	)
Amortization (*)		(2,034,121)		(675,305	)		(87,051,738	)		(1,221,313	)		(11,050,749	)		(438,016	)		(102,471,242	)
Foreign currency translation differences		124,168		346,227			(213,403,284	)		17,368			(4,005,420	)		40,688			(216,880,253	)
Other increases (decreases)		(1,034,986)		10,226,003			(122,496,329	)		720,158			(8,058,280	)		45,901			(120,597,533	)
Total changes in identifiable intangible assets		28,034		10,941,797			(275,228,771	)		182,873			146,527			(333,100	)		(264,262,640	)

Closing balance in identifiable intangible assets at 12-31-2012		10,310,522		44,658,323			1,093,803,169			2,546,806			48,891,809			2,924,945			1,203,135,574

(*) See Note 28, Depreciation, amortization, and impairment loss.

Year ended December 31, 2011


Changes in Intangible Assets	Development Costs, Net			Easements and Water Rights, Net			Concessions, Net			Patents, Registered Trademarks, and Other Rights, Net			Computer Software, Net			Other Identifiable Intangible Assets, Net			Intangible Assets, Net
Changes in Intangible Assets	ThCh$			ThCh$			ThCh$			ThCh$			ThCh$			ThCh$			ThCh$

Opening balance at 1-1-2011		8,741,017			31,698,726			1,360,183,077			2,872,877			44,247,169			4,843,539			1,452,586,405
Changes in identifiable intangible assets
Additions		2,897,310			500,709			173,836,828			718,039			13,095,987			22,860			191,071,733
Disposals		(813,771	)		-			(8,618,410	)		-			(182,691	)		(20,853	)		(9,635,725	)
Amortization		(1,044,292	)		(341,988	)		(88,675,941	)		(1,379,500	)		(10,797,238	)		(442,587	)		(102,681,546	)
Foreign currency translation differences		517,527			276,864			(17,416,448	)		98,355			1,325,759			161,688			(15,036,255	)
Other increases (decreases)		(15,303	)		1,582,215			(50,277,166	)		54,162			1,056,296			(1,306,602	)		(48,906,398	)

Total changes in identifiable intangible assets		1,541,471			2,017,800			8,848,863			(508,944	)		4,498,113			(1,585,494	)		14,811,809

Closing balance in identifiable intangible assets at 12-31-2011		10,282,488			33,716,526			1,369,031,940			2,363,933			48,745,282			3,258,045			1,467,398,214

According to the Group management’s estimates and projections, the expected future cash flows attributable to intangible assets allow recovery of the carrying amount of these assets recorded as of December 31, 2012 (see Note 3.e).

As of December 31, 2012 and 2011, the Company does not have significant intangible assets with an indefinite useful life.

14.

GOODWILL

The following table shows goodwill by the Cash-Generating Unit or group of Cash-Generating Units to which it belongs and changes as of December 31, 2012 and 2011:


Company	Opening balance 1-1-2011 ThCh$		Impairment loss recorded in Income Statement ThCh$		Foreign Currency Translation ThCh$		Closing balance 12-31-2011 ThCh$		Transfers from mergers ThCh$		Foreign currency translation ThCh$			Closing balance 12-31-2012 ThCh$
Empresa Distribuidora Sur S.A. (*)		8,713,277		(8,931,451)		218,174		-		-		-		-
Ampla Energia e Serviços S.A.		239,730,987		-		(3,207,683)		236,523,304		-		(37,853,331	)	198,669,973
Investluz S.A.		121,789,611		-		(1,629,587)		120,160,024		-		(19,230,482	)	100,929,542
Empresa Eléctrica de Colina Ltda.		2,240,478		-		-		2,240,478		-		-		2,240,478
Compañía Distribuidora y Comercializadora de Energía S.A.		10,536,443		-		1,053,186		11,589,629		-		153,012		11,742,641
Empresa Eléctrica Pangue S.A. (***)		3,139,337		-		-		3,139,337		(3,139,337)		-		-
Endesa Costanera S.A. (**)		5,315,282		(5,448,372)		133,090		-		-		-		-
Hidroeléctrica el Chocón S.A.		12,509,433		-		313,227		12,822,660		-		(2,476,733)		10,345,927
Compañía Eléctrica San Isidro S.A. (***)		1,516,768		-		-		1,516,768		3,139,337		-		4,656,105
Empresa de Energía de Cundinamarca S.A.		7,348,467		-		734,527		8,082,994		-		106,715		8,189,709
Empresa de Distribución Eléctrica de Lima Norte S.A.A.		38,505,616		-		6,005,693		44,511,309		-		(1,184,185)		43,327,124
Cachoeira Dourada S.A.		87,903,465		-		(1,176,179)		86,727,286		-		(13,879,886	)	72,847,400
Edegel S.A.A.		72,931,068		-		10,848,527		83,779,595		-		(2,228,883)		81,550,712
Emgesa S.A. E.S.P.		4,673,418		-		467,264		5,140,682		-		66,588		5,207,270
Chilectra S.A.		128,374,362		-		-		128,374,362		-		-		128,374,362
Empresa Nacional de Electricidad S.A.		731,782,459		-		-		731,782,459		-		-		731,782,459
Inversiones Distrilima S.A.		11,453		-		1,786		13,239		-		(352)		12,887

Total		1,477,021,924		(14,379,823)		13,762,025		1,476,404,126		-		(76,527,537	)	1,399,876,589

F-57

According to the Group management’s estimates and projections, the expected future cash flows projections attributable to the Cash-Generating Units or groups of Cash-Generating Units to which the acquired goodwill has been allocated allow recovery of its carrying value as of December 31, 2012 and 2011 (see Note 3.e).

(*) See Note 15.d) viii

(**) See Note 34.5

(***) Empresa Eléctrica Pangue S.A. was merged with Compañía Eléctrica San Isidro S.A. on May 2, 2012; it is the latter company that legally continues to exist.

The origin of the goodwill is detailed below:

1.- Ampla Energia e Serviços S.A.

On November 20, 1996, Enersis S.A. and Chilectra S.A., together with Endesa S.A. and Electricidad de Portugal, acquired a controlling stake in the company Cerj S.A. (now Ampla de Energía) of Rio de Janeiro in Brazil. Enersis S.A. and Chilectra S.A. together bought 42% of the total shares in an international public bidding process held by the Brazilian government.

Enersis S.A. and Chilectra S.A. also bought an additional 18.5% on December 31, 2000, so that they then held a total 60.5% stake, directly and indirectly.

2.- Compañía Energética Do Ceará S.A. (Coelce)

Between 1998 and 1999, Enersis S.A. and Chilectra S.A., together with Endesa S.A., acquired the company Compañía de Distribución Eléctrica del Estado de Ceará (Coelce) in northeast Brazil in an international public bidding process held by the Brazilian government.

3.- Empresa Eléctrica de Colina Ltda.

On September 30, 1996, Chilectra S.A. acquired 100% of the company Empresa Eléctrica de Colina Ltda. from the investment company Saint Thomas S.A., which is neither directly nor indirectly related to Chilectra S.A.

4.- Compañía Distribuidora y Comercializadora de Energía S.A. (Codensa S.A. E.S.P.)

On October 23, 1997, Enersis S.A. and Chilectra S.A., together with Endesa S.A., acquired 48.5% of Colombiana Codensa S.A., a company that distributes electricity in Santa Fé de Bogotá in Colombia. The purchase took place through an international public bidding process held by the Colombian government.

5.- Empresa Eléctrica Pangue S.A.

On July 12, 2002, Endesa Chile acquired 2.51% of the shares of Empresa Eléctrica Pangue S.A. through a put option held by the minority shareholder Internacional Finance Corporation (IFC).

6.- Hidroeléctrica el Chocón S.A.

On August 31, 1993, Endesa Chile acquired 59% of Hidroeléctrica El Chocón in an international public bidding process held by the Argentine government.

7.- Compañía Eléctrica San Isidro S.A.

On August 11, 2005, Endesa Chile bought the shares of the company Inversiones Lo Venecia Ltda., whose only asset was a 25% interest in the company San Isidro S.A. (minority shareholder purchase).

8.- Empresa de Energía de Cundinamarca S.A.

On March 31, 2009, the company Distribuidora de Energía de Cundinamarca S.A. (DECA), a joint venture by Empresa Eléctrica de Bogotá (51.003%) and our subsidiary Codensa S.A. (48.997%), acquired 82.34% of Empresa de Energía de Cundinamarca in a public bidding process held by the Colombian government.

F-58

9.- Empresa de Distribución Eléctrica de Lima Norte S.A.A.

On October 15, 2009 in a transaction on the Lima Stock Exchange, Enersis S.A. purchased an additional 24% interest in Empresa de Distribución Eléctrica de Lima Norte S.A.A. (Edelnor).

10.- Cachoeira Dourada S.A.

On September 5, 1997, our subsidiary Endesa Chile acquired 79% of the company Cachoeira Dourada S.A. in the state of Goias in a public bidding process held by the Brazilian government.

11.- Edegel S.A.A.

On October 9, 2009, in a transaction on the Lima Stock Exchange in Peru, our subsidiary Endesa Chile acquired an additional 29.3974% interest in Edegel S.A.A.

12.- Emgesa S.A. E.S.P.

On October 23, 1997, our subsidiary Endesa Chile, together with Endesa S.A., bought 48.5% of Emgesa S.A. E.S.P. in Colombia. The purchase was made in an international public bidding process held by the Colombian government.

13.- Chilectra S.A.

In November 2000, Enersis S.A. purchased an additional 25.4% interest in the subsidiary Chilectra S.A. through a purchasing power of attorney in a public bidding process, reaching a 99.99% stake in the company.

14.- Empresa Nacional de Electricidad S.A.

On May 11, 1999, Enersis S.A. acquired an additional 35% in Endesa Chile in a public bidding process on the Santiago Stock Exchange and by buying shares in the U.S. (30% and 5%, respectively), reaching a 60% interest in the generation company.

15.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment as of December 31, 2012 and 2011:


Classes of Property, Plant, and Equipment, Net	12-31-2012 ThCh$		12-31-2011 ThCh$
Classes of Property, Plant, and Equipment, Net
Property, Plant, and Equipment, Net		7,243,620,209	7,242,731,006
Construction in progress		861,933,364	1,072,203,347
Land		107,027,332	103,166,702
Buildings		96,068,676	103,542,090
Plant and equipment		6,079,114,959	5,864,732,615
Fixtures and fittings		74,559,610	71,886,276
Other		24,916,268	27,199,976

Classes of Property, Plant, and Equipment, Gross	12-31-2012 ThCh$		12-31-2011 ThCh$

Property, Plant, and Equipment, Gross		12,764,909,059	12,611,068,947
Construction in progress		861,933,364	1,072,203,347
Land		107,027,332	103,166,702
Buildings		171,955,290	181,206,892
Plant and equipment		11,381,747,327	11,016,684,462
Fixtures and fittings		209,882,929	203,946,217
Other		32,362,817	33,861,327

Classes of Accumulated Depreciation and Impairment, Property, Plant, and Equipment	12-31-2012 ThCh$		12-31-2011 ThCh$

Classes of Accumulated Depreciation and Impairment, Property, Plant, and Equipment		(5,521,288,850)	(5,368,337,941)
Buildings		(75,886,614)	(77,664,802)
Plant and equipment		(5,302,632,368)	(5,151,951,847)
Fixtures and Fittings		(135,323,319)	(132,059,941)
Other		(7,446,549)	(6,661,351)

F-59

The detail of property, plant, and equipment during the 2012 and 2011 fiscal years is as follows:


Changes in 2012		Construction in Progress ThCh$			Land ThCh$			Buildings, Net ThCh$			Plant and Equipment, Net ThCh$			Fixtures and Fittings Net ThCh$			Other Property, Plant, and Equipment, Net ThCh$			Property, Plant, and Equipment, Net ThCh$
Opening balance at January 1, 2012			1,072,203,347			103,166,702			103,542,090			5,864,732,615			71,886,276			27,199,976		7,242,731,006
Changes	Additions		497,524,341			244,787			365,995			18,040,552			8,078,852			-		524,254,527
	Disposals		(7,978	)		(299,846	)		(24,511	)		(2,348,958	)		(249,031	)		-		(2,930,324)
	Depreciation expense (*)		-			-			(5,036,485	)		(319,018,617	)		(15,371,768	)		(956,611	)	(340,383,481)
	Impairment loss entered in Income Statement (*)		-			-			-			(12,578,098	)		-			-		(12,578,098)
	Foreign currency translation differences		(23,742,485	)		(554,413	)		(5,657,569	)		(134,227,522	)		(4,723,849	)		(415,196	)	(169,321,034)
	Other increases (decreases)		(684,043,861	)		4,470,102			2,879,156			664,514,987			14,939,130			(911,901	)	1,847,613
	Total changes		(210,269,983	)		3,860,630			(7,473,414	)		214,382,344			2,673,334			(2,283,708	)	889,203
Closing balance at December 31, 2012			861,933,364			107,027,332			96,068,676			6,079,114,959			74,559,610			24,916,268		7,243,620,209

(*) See Note 28, Depreciation, amortization, and impairment loss.


Changes in 2011		Construction in Progress ThCh$			Land ThCh$			Buildings, Net ThCh$			Plant and Equipment, Net ThCh$			Fixtures and Fittings, Net ThCh$			Other Property, Plant, and Equipment, Net ThCh$			Property, Plant, and Equipment, Net ThCh$
Opening balance at January 1, 2011			810,013,619			122,864,336			103,735,435			5,613,164,538			74,513,233			27,649,494		6,751,940,655
Changes	Additions		512,145,923			601,827			560,334			26,297,088			8,744,381			228		548,349,781
	Disposals		(894,857	)		(27,495	)		(11,695	)		(1,478,364	)		(276,423	)		-		(2,688,834)
	Depreciation expense		(47,084	)		-			(4,917,847	)		(292,351,527	)		(23,896,598	)		(1,005,434	)	(322,218,490)
	Impairment loss entered in Income Statement		-			-			-			(106,449,843	)		-			-		(106,449,843)
	Foreign currency translation differences		19,527,280			4,656,121			4,175,863			318,631,910			14,856,991			196,655		362,044,820
	Other increases (decreases)		(268,541,534	)		(24,928,087	)		-			306,918,813			(2,055,308	)		359,033		11,752,917
	Total changes		262,189,728			(19,697,634	)		(193,345	)		251,568,077			(2,626,957	)		(449,518	)	490,790,351
Closing balance at December 31, 2011			1,072,203,347			103,166,702			103,542,090			5,864,732,615			71,886,276			27,199,976		7,242,731,006

Additional information on property, plant and equipment, net

a) Main investments

Material investments in the electricity generation business include developments in the program to create new capacity.

In Colombia, the Central Hidráulica El Quimbo, a hydroelectric dam with 400 MW of installed capacity and an average annual generation of some 2,216 GWH, is currently under construction.

b) Finance leases

As of December 31, 2012 and 2011, property, plant and equipment includes ThCh$ 126,760,139 and ThCh$ 137,092,811 respectively, in leased assets classified as finance leases.

The present value of future lease payments derived from these finance leases is as follows:


	12-31-2012						12-31-2011
	Gross ThCh$		Interest ThCh$		Present Value ThCh$		Gross ThCh$		Interest ThCh$		Present Value ThCh$
Less than one year		12,154,120		1,929,701		10,224,419		15,954,189		2,145,937	13,808,252
From one to five years		40,346,759		3,945,765		36,400,994		39,105,238		5,827,660	33,277,578
More than five years		13,016,926		2,211,594		10,805,331		27,619,488		2,457,926	25,161,562
Total		65,517,805		8,087,060		57,430,744		82,678,915		10,431,523	72,247,392

Leasing assets primarily relate to:

1. Endesa Chile S.A.: a lease agreement for Electric Transmission Lines and Installations (Ralco-Charrúa 2X220 KV) entered into between Endesa Chile and Abengoa Chile S.A. The lease agreement has a 20-year maturity and bears interest at an annual rate of 6.5%.

2. Edegel S.A.A.: lease agreements to finance the project of converting the Ventanilla thermoelectric plant to a combined cycle plant. The agreements were signed between Edegel S.A.A. and the financial institutions BBVA - Banco Continental, Banco de Crédito del Perú, Citibank del Peru, and Banco Internacional del Peru - Interbank. These agreements have an average term of 8 years and bear interest at an annual rate of Libor + 2.5% as of December 31, 2012.

F-60

The company also has an agreement with Scotiabank, which financed the construction of a new open cycle plant at the Santa Rosa Plant. This agreement has a term of 9 years and bears interest an annual rate of Libor + 1.75%.

c) Operating leases

The consolidated statements of income at December 31, 2012, 2011, and 2010 include ThCh$ 18,905,120, ThCh$ 17,042,089, and ThCh$ 16,980,825, respectively, corresponding to accrual during these periods of operating lease contracts for material assets in operation.

As of December 31, 2012, 2011, and 2010 the total future lease payments under those contracts are as follows:


	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$
Less than one year		18,932,624		7,690,811	5,655,232
From one to five years		34,901,830		21,347,042	19,916,962
More than five years		69,870,162		41,634,563	26,625,179
Total		123,704,616		70,672,416	52,197,373

d) Other information

i) As of December 31, 2012 and 2011, the Group had contractual commitments for the acquisition of property, plant and equipment amounting to ThCh$ 229,011,250 and ThCh$ 179,872,981, respectively

ii) As of December 31, 2012 and 2011, the Group had property, plant and equipment pledged as security for liabilities in the amount of ThCh$ 175,143,405 and ThCh$ 328,844,716, respectively (see Note 34).

iii) The Company and its foreign subsidiaries have insurance policies for risk, earthquake, machinery breakdown and damages for business interruption with a US$300 million limit in the case of generating companies and a US$30 million limit for distribution companies, including business interruption coverage. The premiums associated with these policies are presented under the line item “Prepayments” within assets.

iv) GasAtacama, in which Endesa Chile has a 50% ownership interest, consolidated using the proportional integration method, has, among other assets, a combined-cycle electricity generation plant in northern Chile. As importing natural gas from neighboring countries was not possible, GasAtacama has been forced to generate electricity using alternative fuels, the cost of which significantly increased since the last few months of 2007 due to increases in oil prices. As a result, the company filed lawsuits for early termination of its contract with distributor Emel. On January 25, 2008, a ruling was issued in arbitration proceedings on this matter to deny early termination. This situation significantly reduced the recoverable value of the aforementioned plant and, therefore, as of December 31, 2007, an impairment provision of US$110 million was recorded.

v) The asset situation, primarily that of works and infrastructure, involving facilities built to support power generation in the SIC grid, has changed since 1998, due primarily to the installation in the SIC of new thermoelectric plants, the arrival of LNG, and new projects that will be starting up soon. This results in a new configuration of ample supply for the coming years, in which it is expected that these facilities will not need to be used. Therefore, as of December 31, 2009, the company recorded an impairment provision of ThCh$ 43,999,600 for these assets.

vi) As a result of the February 27, 2010 earthquake in Chile, some of our plant and equipment were partially or totally impaired. The impact on our total assets, however, is minor as the only facilities that suffered some damage in infrastructure were the Bocamina I and Bocamina II plants, as well as a few other assets from our distribution business.

Due to these impairments, we have written down ThCh$ 369,643 in assets. Additionally, the Group had to incur expenditures related to repair and capital improvements totaling ThCh$ 9,733,426, primarily at the Bocamina I plant. All of the disbursements incurred are covered by insurance, which carries a US$2.5 million policy deductible.

It is worth noting that the Group has the necessary insurance coverage for these types of exceptional claims, which provide coverage for material damage as well as business interruption (see Note 25).

vii) On October 16, 2012, Endesa Chile began the collection process on all of the bank performance bonds guaranteeing compliance with the works and correct, timely execution of these works as specified in the agreement “Bocamina Thermal Plant Expansion Project,” contract ACP-003.06. This is a turnkey project for a 350 MW coal-fired thermal generation plant (“the contract”) signed on July 25, 2007 between Empresa Nacional de Electricidad S.A. (“the owner”) and the consortium consisting of (i) the Chilean company Ingeniería y Construcción Tecnimont Chile y Compañía Limitada; (ii) the Italian company Tecnimont SpA; (iii) the Brazilian company Tecnimont do Brasil Construcao e Administracao de Projetos Ltda; (iv) the Slovakian company Slovenske Energeticke Strojarne a.s. (“SES”); and (v) the Chilean company Ingeniería y Construcción SES Chile Limitada; (all referred to collectively as “the Contractor” or “the Consortium”).

F-61

These performance bonds total US$74,795,164.44 and UF 796,594.29 (approximately US$38,200,000). The amount actually collected on the bonds as of December 31, 2012 was US$93,996,585.73, with US$18,940,294.84 still pending collection.

Collection was made on these bank performance bonds to reduce the costs incurred by the company due to breach of contract; they are capitalized in the Project.

Together collecting on the bonds, Endesa Chile has reserved all of the rights conferred upon it under the Contract and applicable national legislation to demand complete, timely compliance with the obligations agreed to by the Contractor.

On October 17, 2012, Endesa Chile filed an arbitration request with the International Chamber of Arbitration of Paris in order to enforce the rights conferred upon it under the Contract.

viii) Our subsidiary Companhia de Interconexão Energética (“CIEN”) was initially in the business of selling electricity in Argentina and Brazil. However, because of the reduction in the availability of power generation and physical guarantee of energy and its associated power, the Company has focused its business on a different compensation structure that is not based on the purchase and sale of energy between the countries. Given the strategic importance of the Company’s assets in the relations between Brazil and Argentina, the Company and the Brazilian Government have jointly drawn up a new business plan model changing its selling activity to an electricity transmission activity with payment of a fixed compensation. This new plan involves integrating its transmission lines with the Brazilian transmission grid operated by the Brazilian Government.

In prior periods, the Argentine and Uruguayan Governments formalized toll payments with the Company to transport energy between the two countries. Management considers that this situation further emphasizes the importance of the application made to the Brazilian Government to approve the new business plan and considers that it will probably be approved. In addition, on June 4, 2010 the Company signed a new transmission contract for a six-month period for a total of US$155 million to cover the energy transmission required by the Argentine Government.

Finally, on April 5, 2011, the Diario Oficial (The Official Gazette) published Portarías Ministeriales (Ministerial Decrees) 210/2011 and 211/2011 that equipped Companhia de Interconexao Energética, S.A. (CIEN) with a regulated interconnection line involving payment of a regulated toll. The Receita Anual Permitida (RAP), or income permitted annually, corresponded to 248 million Brazilian reals, to be adjusted according to the Broad National Consumer Price Index (IPCA) every year in June and with the rate to be reviewed every four years. The Line 1 concession lasts until June 2020 and the Line 2 concession until July 2022, with compensation provisions for non-amortized investments. This successfully concludes the change in CIEN’s business model that we had previously reported. (see Note 3a).

ix) Our Argentine subsidiary, Empresa Distribuidora Sur S.A., has seen its financial equilibrium seriously affected by the delay in the compliance with certain points of the Acta de Acuerdo agreement signed with the Argentine Government, particularly the twice-yearly rate adjustments recognized through the cost-monitoring mechanism (MMC) and the establishment of an Integral Rate Review (IRT) as provided for in this agreement.

At the close of the 2011 fiscal year, Enersis recorded an impairment loss of ThCh$ 106,449,843 for the Property, Plant and Equipment of Empresa Distribuidora Sur S.A., as well as an additional loss of ThCh$ 8,931,451 for the complete impairment of the purchase goodwill that was assigned to its Argentine subsidiary (see Note 14). This provisioncovers the total equity risk that Edesur represents for the Enersis Group.

x) At the end of the 2012 fiscal year, our subsidiary Compañía Eléctrica Tarapacá S.A. recorded an impairment loss for ThCh$ 12,578,098 to adjust the book value of its Properties, plants, and equipment to their recoverable value (see Note 3.e).

16.

INVESTMENT PROPERTY

The detail of the composition of, and changes in, investment property during the 2012 and 2011 fiscal years is as follows:


Investment Properties	ThCh$

Opening balance at January 1, 2011		33,019,154
Additions		2,716,250
Disposals		(977,173)
Depreciation expense		(24,029)
Impairment losses reversed, recognized in the consolidated statement of income (*)		3,321,687
Balance at December 31, 2011		38,055,889
Additions		7,936,694
Disposals		(1,646,504)
Depreciation expense		(69,374)
Impairment losses reversed, recognized in the consolidated statement of income (*)		2,646,265
Closing balance investment properties December 31, 2012		46,922,970

(*) See Note 28.

F-62

The fair value of the Group’s investment properties as of December 31, 2011, determined on the basis of valuations carried out internally, was ThCh$ 47,410,152. As of December 31, 2012, the market value of these properties had not changed significantly.

The selling price of investment properties disposed of in the 2012 and 2011 fiscal years was ThCh$ 9,594,069 and ThCh$ 5,102,508, respectively.

The amounts recognized in profit or loss during the 2012, 2011, and 2010 fiscal years as direct operating expenses arising from investment properties were not significant.

The Group has insurance policies to cover operational risks of its investment properties, as well as to cover legal claims against the Group that could potentially arise from exercising its business activity. The Group’s management considers that the insurance policy coverage is sufficient against the risks involved.

17.

DEFERRED TAX

a. Deferred taxes recognized by temporary differences at December 31, 2012 and 2011 are as follows:


		Deferred Tax Assets				Deferred Tax Liabilities
Temporary Differences temporal	12-31-2012		12-31-2011		12-31-2012		12-31-2011
Temporary Differences temporal	ThCh$		ThCh$		ThCh$		ThCh$
Deferred tax relating to depreciations		78,039,178		87,992,490		411,871,841		455,205,366
Deferred tax relating to amortizations		-		-		-		6,082,237
Deferred tax relating to accruals		8,988,436		12,161,705		12,777,749		5,034,474
Deferred tax relating to provisions		44,943,044		86,876,561		-		4,431,328
Deferred tax relating to foreign exchange contracts		2,252,322		31,195,995		-		107,097
Deferred tax relating to post-employment benefit obligations		46,768,738		38,807,414		304,470		5,074,020
Deferred tax relating to revaluations of financial instruments		47,320,153		37,813,186		6,417,993		880,379
Deferred tax relating to tax losses		16,442,922		22,117,495		-		-
Deferred tax relating to other items		82,912,647		62,973,782		87,653,993		31,623,354
Total Deferred Taxes		327,667,440		379,938,628		519,026,046		508,438,255

b. The following table presents the changes in deferred taxes in the Consolidated Statement of Financial Position for the 2012 and 2011 fiscal years:


Changes in Deferred Taxes	Assets ThCh$		Liabilities ThCh$
Balance at January 1, 2011		452,634,364		555,923,578
Increase (decrease) in profit or loss		(48,785,847)		(26,492,538)
Increase (decrease) in Comprehensive Income		14,647,632		3,942,971
Foreign currency translation		8,826,145		33,797,031
Other increase (decrease)		(47,383,666)		(58,732,787)
Balance at December 31, 2011		379,938,628		508,438,255
Increase (decrease) in profit or loss		29,866,694		78,903,593
Increase (decrease) in Comprehensive Income		(719,440)		3,161,786
Foreign currency translation		(31,819,436)		(21,323,544)
Other increase (decrease)		(49,599,006)		(50,154,044)
Balance at December 31, 2012		327,667,440		519,026,046

Recovery of deferred tax assets will depend on whether sufficient tax profits are obtained in the future. The Company believes that the future profit projections for its numerous subsidiaries will allow these assets to be recovered.

c. As of December 31, 2012 and 2011, the Group has not recognized deferred tax assets related to tax losses totaling ThCh$ 50,426,796 and ThCh$ 39,313,993, respectively. See Note 3.o.

The Enersis Group has not recognized deferred tax liabilities for taxable temporary differences associated with investment in subsidiaries, associates and joint ventures, as it is able to control the timing of the reversal of the temporary differences and considers that it is probable that such temporary differences will not reverse in the foreseeable future. The aggregate amount of taxable temporary differences associated with investments in subsidiaries, associates, and joint ventures for which deferred tax liabilities have not been recognized totaled ThCh$ 2,283,224,481 as of December 31, 2012 (ThCh$ 2,204,931,942 as of December 31, 2011).

The Group is potentially subject to income tax audits by the tax authorities of each country in which the Group operates. Such tax audits can be performed until the applicable statute of limitations expires.

F-63

Tax audits by their nature are often complex and can require several years to complete. The following table presents a summary of tax years potentially subject to examination:


Country		Period
Chile		2007-2012
Argentina		2007-2012
Brazil		2007-2012
Colombia		2010-2012
Peru		2008-2012

Given the range of possible interpretations of tax standards, the results of any future inspections carried out by tax authorities for the years subject to audit can give rise to tax liabilities that cannot currently be quantified objectively. Nevertheless, Enersis Management estimates that the liabilities, if any, that may arise from such audits, would not significantly impact the companies’ future results.

The effects of deferred tax on the components of other comprehensive income are as follows:


Effects of Deferred Tax on the Components of Other Comprehensive Income	December 31, 2012						December 31, 2011						December 31, 2010
	Amount Before Tax ThCh$		Income Tax Expense (Benefit) ThCh$		Amount After Tax ThCh$		Amount Before Tax ThCh$		Income Tax Expense (Benefit) ThCh$		Amount After Tax ThCh$		Amount Before Tax ThCh$		Income Tax Expense (Benefit) ThCh$		Amount After Tax ThCh$
Available-for sale financial assets		515		(569)		(54)		(55,959)		9,513		(46,446)		(179)		31		(148)
Cash flow hedge		66,841,875		(25,726,629)		41,115,246		(88,032,492)		14,110,400		(73,922,092)		30,911,303		(5,301,050)		25,610,253
Foreign currency translation		(363,936,877)		-		(363,936,877)		211,929,739		-		211,929,739		(138,554,045)		-		(138,554,045)
Actuarial income on defined-benefit pension plans		(15,001,248)		4,662,040		(10,339,208)		(62,246,623)		23,078,884		(39,167,739)		(48,495,375)		16,515,279		(31,980,096)
Income tax related to components of other income and expenses debited or credited to Equity		(312,095,735)		(21,065,158)		(333,160,893)		61,594,665		37,198,797		98,793,462		(156,138,296)		11,214,260		(144,924,036)

18.

OTHER FINANCIAL LIABILITIES

The balance of other financial liabilities as of December 31, 2012 and 2011 is as follows:


Other Financial Liabilities		December 31, 2012				December 31, 2011
		Current		Non-current		Current		Non-current
		ThCh$		ThCh$		ThCh$		ThCh$

Interest-bearing loans			662,888,607		2,687,724,262		661,974,731		3,049,197,963
Hedging derivatives (*)			4,850,754		233,368,171		6,200,643		212,913,735
Non-hedging derivatives (**)			-		-		807,105		-
Obligation for Túnel El Melón concession			2,442,847		7,027,436		2,207,755		9,243,595
Other financial liabilities			-		-		892,104		-

	Total		670,182,208		2,928,119,869		672,082,338		3,271,355,293

(*) See Note 20.2.a.

(**) See Note 20.2.b.

F-64

18.1

Interest- bearing borrowings

The detail of current and non-current interest-bearing borrowings as of December 31, 2012 and 2011 is as follows:


		December 31, 2012				December 31, 2011
		Current		Non-current		Current		Non-current
Classes of Loans that Accrue Interest		ThCh$		ThCh$		ThCh$		ThCh$

Bank loans			111,937,937		292,400,621		278,455,859	316,103,001
Unsecured obligations			394,389,956		2,204,708,298		242,785,757	2,439,913,903
Secured obligations			4,880,687		4,689,387		10,660,476	9,635,108
Finance leases			10,224,419		47,206,325		13,808,252	58,439,140
Other loans			141,455,608		138,719,631		116,264,387	225,106,811

	Total		662,888,607		2,687,724,262		661,974,731	3,049,197,963

Bank loans by currency and contractual maturity as of December 31, 2012 and 2011 are as follows:

-Summary of Bank Loans by currency and contractual maturity


					Current						Non-current
					Maturity				Total Current at 12-31-2012		Maturity					Total Non- current at 12-31-2012
			Secured/	One to Three Months		Three to Twelve Months			Total Current at 12-31-2012	One to Three Years		Three to Five Years		More than Five Years		Total Non- current at 12-31-2012
Country	Currency	Country	Unsecured	ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$

Chile	US$	1.76%	Unsecured		354,739		1,191,983		1,546,722		97,967,390		-		-	97,967,390
Chile	Ch$	4.90%	Unsecured		432		-		432		-		-		-	-
Peru	US$	3.49%	Unsecured		1,806,758		444,835		2,251,593		10,632,998		25,699,999		12,010,552	48,343,549
Peru	Sol	5.50%	Unsecured		187,239		-		187,239		-		1,875,756		20,633,302	22,509,058
Argentina	US$	8.91%	Unsecured		7,214,852		4,421,192		11,636,044		7,368,666		-		-	7,368,666
Argentina	Ar$	20.96%	Unsecured		29,367,103		25,564,977		54,932,080		10,429,806		-		-	10,429,806
Colombia	CP	8.12%	Unsecured		6,817,245		-		6,817,245		-		82,656,349		-	82,656,349
Brazil	US$	7.79%	Unsecured		-		6,199,249		6,199,249		13,651,212		7,623,414		1,851,177	23,125,803
Brazil	Real	7.47%	Unsecured		5,001,762		23,365,571		28,367,333		-		-		-	-

			Total		50,750,130		61,187,807		111,937,937		140,050,072		117,855,518		34,495,031	292,400,621


				Current						Non-current
				Maturity						Maturity						Total Non- Current at 12-31-2011
Country	Currency	Country	Secured/ Unsecured	One to Three Months		Three to Twelve Months		Total Current at 12-31-2011		One to Three Years		Three to Five Years		More than Five Years
					ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$	ThCh$

Chile	US$	1.97%	Unsecured		84,500		1,607,710		1,692,210		107,025,578		849,449		-	107,875,027
Peru	US$	3.63%	Unsecured		2,354,628		8,838,878		11,193,506		4,296,544		19,212,039		26,158,087	49,666,670
Peru	Sol	5.20%	Unsecured		310,428		1,541,618		1,852,046		-		-		30,832,352	30,832,352
Argentina	US$	5.28%	Unsecured		494,597		6,393,975		6,888,572		17,983,101		1,598,484		-	19,581,585
Argentina	Ar$	21.17%	Unsecured		37,631,229		17,687,954		55,319,183		40,368,276		2,414,084		-	42,782,360
Colombia	CP	6.48%	Unsecured		262,107		86,794,795		87,056,902		-		-		-	-
Brazil	US$	6.05%	Unsecured		-		5,825,541		5,825,541		13,909,371		11,722,036		6,352,599	31,984,006
Brazil	Real	12.89%	Unsecured		9,173,097		99,454,802		108,627,899		33,381,001		-		-	33,381,001

			Total		50,310,586		228,145,273		278,455,859		216,963,871		35,796,092		63,343,038	316,103,001

The fair value of current and non-current bank borrowings totaled ThCh$ 405,226,404 at December 31, 2012 and ThCh$ 582,919,972 at December 31, 2011.

F-65

- Identification of Bank Borrowings by Company


Taxpayer ID No. (RUT)	Company	Country	ID No. Financial Institution	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Type of Amortization	12-2012							12-2011
										Current ThCh$			Non-current ThCh$				Current ThCh$			Non-current ThCh$
										Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non- current	Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non- current
Foreign	Ampla	Brazil	Foreign	Banco Alfa	Brazil	Real	10.23%	10.27%	Semi-annually	-	-	-	-	-	-	-	2,211,773	12,517,876	14,729,649	-	-	-	-
Foreign	Ampla	Brazil	Foreign	Banco do Brasil	Brazil	Real	9.47%	9.29%	At maturity	142,971	23,365,571	23,508,542	-	-	-	-	275,812	-	275,812	27,817,501	-	-	27,817,501
Foreign	Ampla	Brazil	Foreign	Banco HSBC	Brazil	Real	9.93%	9.77%	At maturity	-	-	-	-	-	-	-	176,118	20,863,126	21,039,244	-	-	-	-
Foreign	Ampla	Brazil	Foreign	Banco Itaú	Brazil	Real	10.12%	10.20%	Semi-annually	-	-	-	-	-	-	-	1,694	1,856,820	1,858,514	-	-	-	-
Foreign	Ampla	Brazil	Foreign	Brasdesco	Brazil	Real	9.75%	5.65%	Semi-annually	4,858,791	-	4,858,791	-	-	-	-	6,481,458	7,048,955	13,530,413	5,563,500	-	-	5,563,500
Foreign	Ampla	Brazil	Foreign	Unibanco	Brazil	Real	10.27%	10.29%	Semi-annually	-	-	-	-	-	-	-	26,242	1,479,891	1,506,133	-	-	-	-
Foreign	Central Geradora Termeléctrica Fortaleza S.A.	Brazil	Foreign	IFC - A	Brazil	US$	7.98%	8.04%	Semi-annually	-	2,385,144	2,385,144	5,314,352	6,132,262	-	11,446,614	-	2,426,516	2,426,516	5,406,532	6,238,628	3,470,634	15,115,794
Foreign	Central Geradora Termeléctrica Fortaleza S.A.	Brazil	Foreign	IFC - B	Brazil	US$	3.03%	3.02%	Semi-annually	-	3,755,999	3,755,999	8,336,860	-	-	8,336,860	-	3,399,025	3,399,025	8,502,839	4,712,630	-	13,215,469
Foreign	Central Geradora Termeléctrica Fortaleza S.A.	Brazil	Foreign	IFC - C	Brazil	US$	12.09%	12.31%	Semi-annually	-	58,106	58,106	-	1,491,152	1,851,177	3,342,329	-	-	-	-	770,778	2,881,965	3,652,743
96,800,570-7	Chilectra S.A.	Chile		Bank credit lines	Chile	Ch$	6.60%	6.60%	Other	46	-	46	-	-	-	-	-	-	-	-	-	-	-
Foreign	Chinango S.A.C.	Peru	Foreign	Banco Continental	Peru	Sol	3.85%	3.80%	At maturity	-	-	-	-	-	-	-	3,068	1,541,618	1,544,686	-	-	-	-
Foreign	Chinango S.A.C.	Peru	Foreign	Banco Scotiabank	Peru	US$	4.07%	4.01%	Quarterly	62,786	444,835	507,621	1,186,227	1,186,227	12,010,552	14,383,006	71,315	-	71,315	1,127,370	1,288,422	13,689,484	16,105,276
Foreign	Chinango S.A.C.	Peru	Foreign	Bank Of Nova Scotia	Peru	US$	3.10%	3.06%	Quarterly	18,702	-	18,702	2,391,588	2,391,588	-	4,783,176	-	-	-	-	-	-	-
Foreign	Companhia de Interconexao Energética S.A.	Brazil	Foreign	Santander	Brazil	Real	11.61%	11.80%	Semi-annually	-	-	-	-	-	-	-	-	55,688,134	55,688,134	-	-	-	-
Foreign	Compañía Distribuidora y Comercializadora de Energía S.A.	Colombia	Foreign	Banco Agrario	Colombia	CP	6.27%	6.11%	At maturity	-	-	-	-	-	-	-	262,107	-	262,107	-	-	-	-
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	US$	3.54%	3.49%	Quarterly	-	-	-	7,055,183	22,122,184	-	29,177,367	-	-	-	1,298,813	17,923,617	12,468,603	31,691,033
Foreign	Edegel S.A.A	Peru	Foreign	Banco Scotiabank	Peru	US$	3.45%	3.41%	Quarterly	1,725,270	-	1,725,270	-	-	-	-	-	1,870,716	1,870,716	-	-	-	-
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	US$	2.99%	2.96%	At maturity	-	-	-	-	-	-	-	392,849	1,357,201	1,750,050	-	-	-	-
Foreign	Edegel S.A.A	Peru	Foreign	Banco de Crédito	Peru	US$	1.65%	1.65%	At maturity	-	-	-	-	-	-	-	1,890,464	5,610,961	7,501,425	1,870,361	-	-	1,870,361
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	AV VILLAS	Colombia	CP	9.41%	9.20%	At maturity	162,350	-	162,350	-	7,846,933	-	7,846,933	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco Davivienda	Colombia	CP	8.15%	7.91%	Annual	-	-	-	-	-	-	-	-	8,977,569	8,977,569	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco Santander	Colombia	CP	8.15%	7.91%	Annual	-	-	-	-	-	-	-	-	26,730,428	26,730,428	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bancolombia	Colombia	CP	9.41%	9.20%	At maturity	383,776	-	383,776	-	18,549,169	-	18,549,169	-	21,177,566	21,177,566	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bancolombia	Colombia	CP	9.41%	9.20%	At maturity	126,712	-	126,712	-	6,124,429	-	6,124,429	-	6,430,876	6,430,876	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BBVA Colombia	Colombia	CP	9.41%	9.20%	At maturity	1,037,293	-	1,037,293	-	50,135,818	-	50,135,818	-	23,478,356	23,478,356	-	-	-	-
Foreign	Edelnor	Peru	Foreign	Banco Continental	Peru	Sol	5.43%	5.32%	Quarterly	-	-	-	-	-	-	-	132,120	-	132,120	-	-	7,708,094	7,708,094
Foreign	Edelnor	Peru	Foreign	Banco de Crédito	Peru	Sol	5.43%	5.32%	Quarterly	20,323	-	20,323	-	-	2,813,632	2,813,632	18,741	-	18,741	-	-	2,890,532	2,890,532
Foreign	Edelnor	Peru	Foreign	Banco de Crédito	Peru	Sol	5.43%	5.32%	Quarterly	20,323	-	20,323	-	-	2,813,632	2,813,632	18,741	-	18,741	-	-	2,890,532	2,890,532
Foreign	Edelnor	Peru	Foreign	Banco de Crédito	Peru	Sol	5.43%	5.32%	Quarterly	10,049	-	10,049	-	-	2,438,481	2,438,481	8,847	-	8,847	-	-	2,505,128	2,505,128
Foreign	Edelnor	Peru	Foreign	Banco de Crédito	Peru	Sol	5.43%	5.32%	Quarterly	8,129	-	8,129	-	-	1,125,453	1,125,453	7,497	-	7,497	-	-	1,156,213	1,156,213
Foreign	Edelnor	Peru	Foreign	Banco de Crédito	Peru	Sol	5.43%	5.32%	Quarterly	33,872	-	33,872	-	-	4,689,387	4,689,387	31,235	-	31,235	-	-	4,817,554	4,817,554
Foreign	Edelnor	Peru	Foreign	Banco de Crédito	Peru	Sol	5.43%	5.32%	Quarterly	20,323	-	20,323	-	-	2,813,632	2,813,632	18,741	-	18,741	-	-	2,890,532	2,890,532
Foreign	Edelnor	Peru	Foreign	Banco de Crédito	Peru	Sol	5.43%	5.32%	Quarterly	48,316	-	48,316	-	-	3,939,085	3,939,085	44,826	-	44,826	-	-	4,046,745	4,046,745
Foreign	Edelnor	Peru	Foreign	Banco de Interbank	Peru	Sol	6.90%	6.73%	Quarterly	-	-	-	-	-	-	-	26,612	-	26,612	-	-	1,927,022	1,927,022
Foreign	Edelnor	Peru	Foreign	Banco Scotiabank	Peru	Sol	6.90%	6.73%	Quarterly	25,904	-	25,904	-	1,875,756	-	1,875,756	-	-	-	-	-	-	-
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Foreign	Banco Agrario	Colombia	CP	5.97%	5.81%	Other	2,657,792	-	2,657,792	-	-	-	-	-	-	-	-	-	-	-
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Foreign	AV VILLAS	Colombia	CP	6.32%	6.14%	Other	2,449,322	-	2,449,322	-	-	-	-	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco de la Ciudad de Buenos Aires	Argentina	Ar$	21.72%	21.33%	Quarterly	115,527	6,817,284	6,932,811	-	-	-	-	186,005	-	186,005	8,449,285	-	-	8,449,285
Foreign	Edesur S.A.	Argentina	Foreign	Banco Frances	Argentina	Ar$	18.55%	22.00%	Monthly	486,949	-	486,949	-	-	-	-	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco Galicia	Argentina	Ar$	21.94%	20.00%	Monthly	779,545	-	779,545	-	-	-	-	1,260,656	2,414,082	3,674,738	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco Itaú	Argentina	Ar$	21.52%	19.65%	Quarterly	26,215	2,434,744	2,460,959	-	-	-	-	-	-	-	3,017,603	-	-	3,017,603
Foreign	Edesur S.A.	Argentina	Foreign	Banco Macro	Argentina	Ar$	23.67%	22.31%	Monthly	1,969,227	-	1,969,227	-	-	-	-	-	-	-	2,414,082	-	-	2,414,082
Foreign	Edesur S.A.	Argentina	Foreign	Banco Provincia de Buenos Aires	Argentina	Ar$	16.65%	15.50%	Monthly	9,926	973,898	983,824	-	-	-	-	-	-	-	1,207,041	-	-	1,207,041
Foreign	Edesur S.A.	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	6.24%	6.24%	Monthly	206,886	-	206,886	-	-	-	-	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	21.27%	20.69%	Monthly	57,965	1,460,847	1,518,812	973,898	-	-	973,898	4,834,533	-	4,834,533	2,414,082	-	-	2,414,082
Foreign	Edesur S.A.	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	21.27%	20.69%	Quarterly	46,375	1,168,677	1,215,052	779,118	-	-	779,118	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	21.00%	21.00%	Monthly	4,486,547	-	4,486,547	-	-	-	-	-	-	-	4,224,644	-	-	4,224,644
Foreign	Edesur S.A.	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	21.26%	19.75%	Quarterly	22,135	584,340	606,475	389,560	-	-	389,560	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco Supervielle	Argentina	Ar$	22.39%	19.75%	Monthly	78,860	-	78,860	-	-	-	-	852,036	-	852,036	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	BBVA	Argentina	Ar$	19.55%	18.00%	Monthly	-	-	-	-	-	-	-	42,370	2,414,082	2,456,452	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	BBVA	Argentina	Ar$	21.55%	20.00%	Semi-annually	-	-	-	-	-	-	-	617,884	-	617,884	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Citibank	Argentina	Ar$	21.94%	20.00%	Monthly	1,447,627	-	1,447,627	-	-	-	-	282,930	1,750,209	2,033,139	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Citibank	Argentina	Ar$	24.06%	21.75%	Monthly	6,719	1,409,376	1,416,095	-	-	-	-	311,088	1,810,562	2,121,650	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Comafi	Argentina	Ar$	25.07%	23.50%	Monthly	233,554	-	233,554	-	-	-	-	1,192,058	-	1,192,058	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Standard Bank	Argentina	Ar$	22.83%	23.07%	Monthly	297,709	876,508	1,174,217	292,169	-	-	292,169	-	-	-	3,621,124	-	-	3,621,124
Foreign	Edesur S.A.	Argentina	Foreign	Standard Bank	Argentina	Ar$	22.83%	23.07%	Quarterly	297,709	876,507	1,174,216	292,169	-	-	292,169	-	-	-	-	-	-	-
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	B.N.P. Paribas	USA	US$	6.32%	5.98%	Semi-annually	-	820,076	820,076	1,570,498	-	-	1,570,498	50,233	849,448	899,681	1,698,896	849,449	-	2,548,345

F-66


Taxpayer ID No. (RUT)	Company	Country	ID No. Financial Institution	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Type of Amorti- zation	12-2012							12-2011
										Current ThCh$			Non-current ThCh$				Current ThCh$			Non-current ThCh$
										Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non- current	Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non- current
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	Banco Santander C.H. SA Chile	USA	US$	1.83%	1.06%	At maturity	-	-	-	15,792,106	-	-	15,792,106	-	-	-	17,055,976	-	-	17,055,976
91,081,000-6	Endesa S.A. (Chile)	Chile	97,004,000-5	Banco Santander Chile (Linea Crédito)	Chile	Ch$	6.00%	6.00%	At maturity	277	-	277	-	-	-	-	-	-	-	-	-	-	-
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	Export Development Corporation Loan	USA	US$	1.82%	1.73%	Semi-annually	354,739	343,643	698,382	687,160	-	-	687,160	-	758,262	758,262	1,486,682	-	-	1,486,682
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	The Bank of Tokyo-Mitsubishi, Ltd.	USA	US$	1.83%	1.06%	At maturity	-	-	-	15,792,106	-	-	15,792,106	-	-	-	17,055,976	-	-	17,055,976
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	Scotiabank & Trust Cayman Ltd	Cayman Is	US$	1.83%	1.06%	At maturity	-	28,264	28,264	23,927,433	-	-	23,927,433	-	-	-	-	-	-	-
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	Bank Of America	USA	US$	1.83%	1.06%	At maturity	-	-	-	11,963,716	-	-	11,963,716	-	-	-	-	-	-	-
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	Mercantil Commercebank	USA	US$	1.83%	1.06%	At maturity	-	-	-	9,570,973	-	-	9,570,973	-	-	-	-	-	-	-
91,081,000-6	Endesa S.A. (Chile)	Chile	97,030,000-7	Banco del Estado de Chile	Chile	US$	1.83%	1.06%	At maturity	-	-	-	18,663,398	-	-	18,663,398	-	-	-	-	-	-	-
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	Banco Bilbao Vizcaya Argentaria S.A.NY	USA	US$	1.72%	1.12%	At maturity	-	-	-	-	-	-	-	34,267	-	34,267	30,494,018	-	-	30,494,018
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	Banco Español de crédito S.A. N.Y.B.	USA	US$	1.72%	1.12%	At maturity	-	-	-	-	-	-	-	-	-	-	12,921,194	-	-	12,921,194
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	Caja Madrid, Caja Madrid Miami Agency	USA	US$	1.83%	1.83%	At maturity	-	-	-	-	-	-	-	-	-	-	26,312,836	-	-	26,312,836
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Banco Ciudad	Argentina	Ar$	18.64%	18.64%	At maturity	395,963	-	395,963	-	-	-	-	978,500	-	978,500	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Banco Galicia	Argentina	Ar$	18.75%	18.75%	At maturity	3,395,077	-	3,395,077	-	-	-	-	5,167,489	-	5,167,489	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Banco Itau	Argentina	Ar$	23.75%	23.75%	At maturity	1,341,282	-	1,341,282	-	-	-	-	3,529,419	-	3,529,419	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Banco Macro	Argentina	Ar$	14.00%	16.00%	At maturity	-	-	-	-	-	-	-	368,142	-	368,142	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Banco Nación Argentina	Argentina	Ar$	18.85%	18.85%	At maturity	659,346	1,881,095	2,540,441	402,562	-	-	402,562	3,555,128	-	3,555,128	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Banco Provincia de Buenos Aires	Argentina	Ar$	18.09%	18.09%	At maturity	209,414	-	209,414	-	-	-	-	368,366	-	368,366	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	22.00%	22.00%	At maturity	878,233	-	878,233	-	-	-	-	1,898,686	-	1,898,686	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Standard Bank	Argentina	Ar$	21.00%	21.00%	At maturity	1,390,448	-	1,390,448	-	-	-	-	2,509,954	-	2,509,954	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Banco Supervielle	Argentina	Ar$	20.75%	20.75%	At maturity	1,239,740	-	1,239,740	-	-	-	-	2,566,218	-	2,566,218	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Citibank	Argentina	Ar$	17.00%	17.00%	At maturity	4,347,020	-	4,347,020	-	-	-	-	6,393,434	-	6,393,434	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Credit Suisse International	Argentina	US$	11.45%	11.45%	Quarterly	5,696,590	-	5,696,590	-	-	-	-	44,820	-	44,820	5,195,104	-	-	5,195,104
94,271,000-3	Enersis S.A.	Chile	97,004,000-5	Banco Santander Chile	Chile	Ch$	2.10%	2.10%	At maturity	109	-	109	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Ciudad - Syndicated II	Argentina	Ar$	26.96%	24.11%	Semi-annually	159,475	261,271	420,746	132,576	-	-	132,576	53,063	318,657	371,720	487,596	-	-	487,596
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Galicia - Syndicated II	Argentina	Ar$	26.96%	24.11%	Semi-annually	199,084	326,151	525,235	165,510	-	-	165,510	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Galicia - Syndicated III	Argentina	Ar$	26.95%	24.10%	Semi-annually	555,645	486,949	1,042,594	1,460,847	-	-	1,460,847	167,311	398,233	565,544	3,023,612	603,521	-	3,627,133
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Hipotecario	Argentina	Ar$	27.64%	24.65%	At maturity	339,482	324,633	664,115	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Hipotecario - Syndicated II	Argentina	Ar$	26.96%	24.11%	Semi-annually	199,084	326,151	525,235	165,510	-	-	165,510	66,315	398,233	464,548	609,361	-	-	609,361
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Itau	Argentina	US$	8.30%	8.06%	Quarterly	379,564	1,105,298	1,484,862	1,842,165	-	-	1,842,165	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Itau - Syndicated II	Argentina	Ar$	26.96%	24.11%	Semi-annually	248,855	407,689	656,544	206,887	-	-	206,887	82,953	497,792	580,745	761,701	-	-	761,701
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Itau - Syndicated III	Argentina	Ar$	26.95%	24.10%	Semi-annually	555,645	486,949	1,042,594	1,460,847	-	-	1,460,847	100,996	-	100,996	2,414,203	603,521	-	3,017,724
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Macro	Argentina	Ar$	18.81%	18.00%	At maturity	29,777	1,947,796	1,977,573	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Santander - Syndicated III	Argentina	Ar$	26.95%	24.10%	Semi-annually	555,645	486,949	1,042,594	1,460,847	-	-	1,460,847	100,996	-	100,996	2,414,203	603,521	-	3,017,724
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	22.42%	20.75%	At maturity	98,269	-	98,269	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Santander - Syndicated II	Argentina	Ar$	26.96%	24.11%	Semi-annually	398,343	652,590	1,050,933	331,165	-	-	331,165	132,688	796,817	929,505	1,219,258	-	-	1,219,258
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Deutsche Bank	Argentina	US$	8.30%	8.06%	Quarterly	759,134	2,210,596	2,969,730	3,684,336	-	-	3,684,336	40,734	3,197,006	3,237,740	6,393,999	799,242	-	7,193,241
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Standard Bank	Argentina	US$	8.30%	8.06%	Quarterly	379,564	1,105,298	1,484,862	1,842,165	-	-	1,842,165	40,677	3,196,970	3,237,647	6,393,999	799,242	-	7,193,241
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Standard Bank - Syndicated III	Argentina	Ar$	26.95%	24.10%	Semi-annually	555,645	486,949	1,042,594	1,460,847	-	-	1,460,847	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Standard Bank - Syndicated II	Argentina	Ar$	26.96%	24.11%	Semi-annually	547,656	897,204	1,444,860	455,294	-	-	455,294	283,419	1,095,492	1,378,911	4,090,481	603,521	-	4,694,002
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Standard Bank	Argentina	Ar$	23.14%	21.00%	At maturity	195,452	-	195,452	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Macro I	Argentina	Ar$	23.14%	21.00%	At maturity	293,468	-	293,468	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Hipotecario - Syndicated I	Argentina	Ar$	25.42%	23.31%	Semi-annually	-	-	-	-	-	-	-	16,968	1,013,914	1,030,882	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Itau- Syndicated I	Argentina	Ar$	25.42%	23.31%	Semi-annually	-	-	-	-	-	-	-	25,858	1,545,012	1,570,870	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Santander - Syndicated I	Argentina	Ar$	25.42%	23.31%	Semi-annually	-	-	-	-	-	-	-	25,859	1,545,012	1,570,871	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Standard Bank - Syndicated I	Argentina	Ar$	25.42%	23.31%	Semi-annually	-	-	-	-	-	-	-	20,196	1,207,041	1,227,237	-	-	-	-
Foreign	Hidroeléctrica El Chocón S.A.	Argentina	Foreign	Banco Galicia - Syndicated I	Argentina	Ar$	25.42%	23.31%	Semi-annually	-	-	-	-	-	-	-	8,077	482,816	490,893	-	-	-	-

							Total			50,740,550	61,197,387	111,937,937	140,050,072	117,855,518	34,495,031	292,400,621	50,310,586	228,145,273	278,455,859	216,963,871	35,796,092	63,343,038	316,103,001

Appendix No. 4, letter a), presents details of estimated future cash flows (undiscounted) that the Group will have to disburse to settle the bank loans detailed above.

F-67

18.2

Unsecured Liabilities

The detail of Unsecured Liabilities by currency and maturity as of December 31, 2012 and 2011 is as follows:

- Summary of Unsecured Liabilities by currency and maturity


Country	Currency	Annual Nominal Rate			Secured/ Unsecured	Current						Non-current
						Maturity				Total Current at 12-31-2012		Maturity						Total Non-current at 12-31-2012
						One to Three Months ThCh$		Three to Twelve Months ThCh$		Total Current at 12-31-2012		One to Three Years		Three to Five Years		More than Five Years		Total Non-current at 12-31-2012
						One to Three Months ThCh$		Three to Twelve Months ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$

Chile	US$		7.71	%	Unsecured		20,743,334		192,725,416		213,468,750		271,467,420		123,377,492		145,304,618		540,149,530
Chile	U.F.		5.57	%	Unsecured		-		8,778,822		8,778,822		14,445,679		15,349,506		289,721,460		319,516,645
Peru	US$		6.89	%	Unsecured		785,915		55,795		841,710		7,688,954		9,566,350		18,255,463		35,510,767
Peru	Sol		6.73	%	Unsecured		6,771,045		37,313,862		44,084,907		63,550,103		25,360,206		52,521,139		141,431,448
Colombia	CP		8.01	%	Unsecured		50,177,769		43,631,713		93,809,482		172,916,738		191,051,473		498,675,237		862,643,448
Brazil	Real		11.58	%	Unsecured		6,626,846		26,779,439		33,406,285		64,628,349		152,851,186		87,976,925		305,456,460

					Total		85,104,909		309,285,047		394,389,956		594,697,243		517,556,213		1,092,454,842		2,204,708,298


Country	Currency	Annual Nominal Rate			Secured/ Unsecured	Current						Non-current
						Maturity				Total Current at 12-31-2011		Maturity						Total Non-current at 12-31-2011
						One to Three Months		Three to Twelve Months		Total Current at 12-31-2011		One to Three Years		Three to Five Years		More than Five Years		Total Non-current at 12-31-2011
						ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$

Chile	US$		8.10	%	Unsecured		22,439,241		802,032		23,241,273		396,001,073		236,020,317		157,801,599		789,822,989
Chile	CH$		5.29	%	Unsecured		31,548,592		9,198,469		40,747,061		13,764,742		14,617,263		378,064,242		406,446,247
Peru	US$		6.97	%	Unsecured		853,625		60,597		914,222		5,049,784		13,692,084		19,828,195		38,570,063
Peru	Sol		7.37	%	Unsecured		27,920,075		57,158		27,977,233		80,986,235		42,415,673		28,905,326		152,307,234
Argentina	Ar$		12.28	%	Unsecured		15,571		3,963,560		3,979,131		-		-		-		-
Colombia	CP		8.99	%	Unsecured		1,753,145		36,094,355		37,847,500		131,329,301		76,673,844		574,038,462		782,041,607
Brazil	Real		12.97	%	Unsecured		6,688,369		101,390,968		108,079,337		60,242,802		120,351,829		90,131,132		270,725,763

					Total		91,218,618		151,567,139		242,785,757		687,373,937		503,771,010		1,248,768,956		2,439,913,903

18.3

Secured Liabilities

The detail of Secured Liabilities by currency and maturity as of December 31, 2012 and 2011 is as follows:

- Summary of Secured Liabilities by currency and maturity

Country

Currency

Annual

Nominal

Rate

Secured/

Unsecured

Current

Non-current

Maturity

Total Current at

12-31-2012

Maturity

Total

Non-current at

12-31-2012

One to Three

Months

Three to

Twelve

Months

One to Three

Years

Three to

Five Years

More than

Five Years

ThCh$

Peru

Sol

6.41

Secured

132,316

4,748,371

4,880,687

4,689,387

4,689,387

Total

132,316

4,748,371

4,880,687

4,689,387

Country

Currency

Annual

Nominal

Rate

Secured/

Unsecured

Current

Non-current

Maturity

Total Current at

12-31-2011

Maturity

Total

Non-current at

12-31-2011

One to Three

Months

Three to

Twelve

Months

One to Three

Years

Three to

Five Years

More than

Five Years

ThCh$

Peru

US$

6.15

Secured

10,463,994

10,463,994

Peru

Sol

6.41

Secured

135,886

60,596

196,482

9,635,108

9,635,108

Total

135,886

10,524,590

10,660,476

9,635,108

The fair value of current and non-current secured and unsecured liabilities totaled ThCh$ 2,886,287,734 at December 31, 2012 and ThCh$ 3,209,731,363 at December 31, 2011.

F-68

- Secured and Unsecured Liabilities by Company


Taxpayer ID No. (RUT)	Company	Country	ID No. Financial Institution	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Secured/ Unsecured	12-2012							12-2011
										Current ThCh$			Non-current ThCh$				Current ThCh$			Non-current ThCh$
										Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non- current	Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non- current
Foreign	Chinango S.A.C.	Peru	Foreign	Banco Continental	Peru	US$	6.15%	6.06%	Yes	-	-	-	-	-	-	-	-	10,463,994	10,463,994	-	-	-	-
Foreign	Chinango S.A.C.	Peru	Foreign	Banco Continental	Peru	Sol	6.57%	6.47%	Yes	-	4,748,371	4,748,371	-	-	-	-	-	60,596	60,596	4,817,554	-	-	4,817,554
Foreign	Chinango S.A.C.	Peru	Foreign	Banco Continental	Peru	Sol	6.25%	6.16%	Yes	132,316	-	132,316	4,689,387	-	-	4,689,387	135,886	-	135,886	4,817,554	-	-	4,817,554

					Total Secured Bonds					132,316	4,748,371	4,880,687	4,689,387	-	-	4,689,387	135,886	10,524,590	10,660,476	9,635,108	-	-	9,635,108

Foreign	Ampla	Brazil	Foreign	Bonds, 1st series	Brazil	Real	9.84%	9.93%	No	-	-	-	-	-	-	-	160,282	32,081,924	32,242,206	-	-	-	-
Foreign	Ampla	Brazil	Foreign	Bonds, 1st series	Brazil	Real	10.13%	10.17%	No	-	-	-	-	-	-	-	2,610,374	51,462,513	54,072,887	-	-	-	-
Foreign	Ampla	Brazil	Foreign	Bonds, 1st series	Brazil	Real	9.47%	9.55%	No	76,686	-	76,686	13,171,955	13,668,859	-	26,840,814	147,518	-	147,518	27,931,549	14,103,489	-	42,035,038
Foreign	Ampla	Brazil	Foreign	Bonds, 2nd series	Brazil	Real	13.89%	13.99%	No	106,982	12,242,812	12,349,794	25,009,851	-	-	25,009,851	164,014	-	164,014	-	32,546,476	-	32,546,476
Foreign	Ampla	Brazil	Foreign	Bonds, 2nd series	Brazil	Real	13.49%	14.21%	No	1,937,059	-	1,937,059	-	30,829,074	15,414,538	46,243,612	1,941,239	-	1,941,239	-	17,199,885	34,700,328	51,900,213
Foreign	Ampla	Brazil	Foreign	Bonds, 1st series	Brazil	Real	8.30%	8.38%	No	64,054	-	64,054	-	23,365,572	-	23,365,572	-	-	-	-	-	-	-
Foreign	Ampla	Brazil	Foreign	Bonds, 2nd series	Brazil	Real	11.40%	11.69%	No	2,306,749	-	2,306,749	-	23,717,567	47,973,552	71,691,119	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	B102	Colombia	CP	8.22%	7.97%	No	402,540	-	402,540	-	105,685,080	-	105,685,080	456,111	-	456,111	-	-	104,210,669	104,210,669
Foreign	Codensa	Colombia	Foreign	B103	Colombia	CP	8.47%	8.22%	No	102,531	-	102,531	-	-	21,680,354	21,680,354	181,497	-	181,497	-	-	21,397,849	21,397,849
Foreign	Codensa	Colombia	Foreign	B304	Colombia	CP	5.83%	5.71%	No	21,832,974	-	21,832,974	-	-	-	-	114,096	-	114,096	21,397,849	-	-	21,397,849
Foreign	Codensa	Colombia	Foreign	B502	Colombia	CP	6.81%	6.93%	No	-	-	-	-	-	-	-	30,623	9,019,194	9,049,817	-	-	-	-
Foreign	Codensa	Colombia	Foreign	B503	Colombia	CP	7.94%	7.72%	No	98,018	23,170,878	23,268,896	-	-	-	-	115,603	-	115,603	22,868,952	-	-	22,868,952
Foreign	Codensa	Colombia	Foreign	B503	Colombia	CP	7.94%	7.72%	No	101,709	20,460,835	20,562,544	-	-	-	-	91,853	-	91,853	20,194,220	-	-	20,194,220
Foreign	Codensa	Colombia	Foreign	B604	Colombia	CP	6.80%	6.63%	No	321,197	-	321,197	-	39,295,641	-	39,295,641	372,955	-	372,955	-	38,783,602	-	38,783,602
Foreign	Codensa	Colombia	Foreign	B8	Colombia	CP	9.29%	8.98%	No	349,370	-	349,370	67,751,105	-	-	67,751,105	390,407	-	390,407	66,868,280	-	-	66,868,280
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Itaú 1	Brazil	Real	9.25%	9.31%	No	392,358	-	392,358	12,150,097	12,150,097	-	24,300,194	-	700,207	700,207	-	28,930,201	-	28,930,201
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Itaú 2	Brazil	Real	12.39%	12.50%	No	1,017,294	-	1,017,294	-	49,120,017	24,588,835	73,708,852	-	1,147,175	1,147,175	-	27,571,778	55,430,804	83,002,582
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Itaú 2	Brazil	Real	12.93%	13.02%	No	725,664	14,536,627	15,262,291	14,296,446	-	-	14,296,446	1,664,942	15,999,149	17,664,091	32,311,253	-	-	32,311,253
Foreign	Edelnor	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	Sol	6.06%	5.97%	No	-	78,971	78,971	-	-	9,378,774	9,378,774	-	-	-	-	-	-	-
Foreign	Edelnor	Peru	Foreign	FCR - Macrofondo	Peru	Sol	5.56%	5.49%	No	184,042	-	184,042	-	-	9,378,774	9,378,774	-	-	-	-	-	-	-
Foreign	Edelnor	Peru	Foreign	Interseguro Cia de Seguros Bonds	Peru	Sol	6.28%	6.19%	No	-	100,802	100,802	-	-	7,503,020	7,503,020	-	-	-	-	-	-	-
Foreign	Edelnor	Peru	Foreign	AFP Horizonte	Peru	Sol	6.06%	5.97%	No	-	-	-	-	-	-	-	7,930,354	-	7,930,354	-	-	-	-
Foreign	Edelnor	Peru	Foreign	AFP Horizonte	Peru	Sol	6.56%	6.46%	No	-	47,369	47,369	5,528,788	-	-	5,528,788	48,664	-	48,664	5,679,896	-	-	5,679,896
Foreign	Edelnor	Peru	Foreign	AFP Horizonte	Peru	Sol	7.22%	7.09%	No	67,703	-	67,703	-	2,813,632	-	2,813,632	69,553	-	69,553	-	2,890,532	-	2,890,532
Foreign	Edelnor	Peru	Foreign	AFP Integra	Peru	Sol	5.91%	5.82%	No	-	-	-	-	-	-	-	44,894	-	44,894	-	3,854,043	-	3,854,043
Foreign	Edelnor	Peru	Foreign	AFP Integra	Peru	Sol	6.50%	6.40%	No	-	10,259	10,259	9,469,916	-	-	9,469,916	10,266	-	10,266	9,476,559	-	-	9,476,559
Foreign	Edelnor	Peru	Foreign	AFP Integra	Peru	Sol	8.00%	7.85%	No	168,935	-	168,935	-	5,102,053	-	5,102,053	173,552	-	173,552	-	5,241,499	-	5,241,499
Foreign	Edelnor	Peru	Foreign	AFP Integra	Peru	Sol	8.16%	8.00%	No	133,867	-	133,867	-	3,376,359	-	3,376,359	137,526	-	137,526	-	3,468,639	-	3,468,639
Foreign	Edelnor	Peru	Foreign	AFP Integra	Peru	Sol	5.91%	5.82%	No	-	43,699	43,699	3,751,510	-	-	3,751,510	-	-	-	-	-	-	-
Foreign	Edelnor	Peru	Foreign	AFP Prima	Peru	Sol	6.63%	6.52%	No	-	41,423	41,423	3,751,510	-	-	3,751,510	42,555	-	42,555	-	3,854,043	-	3,854,043
Foreign	Edelnor	Peru	Foreign	AFP Prima	Peru	Sol	6.81%	6.70%	No	15,086	-	15,086	4,689,387	-	-	4,689,387	15,498	-	15,498	4,817,554	-	-	4,817,554
Foreign	Edelnor	Peru	Foreign	AFP Prima	Peru	Sol	6.84%	6.73%	No	181,860	5,627,265	5,809,125	-	-	-	-	186,831	-	186,831	5,781,065	-	-	5,781,065
Foreign	Edelnor	Peru	Foreign	AFP Prima	Peru	Sol	6.94%	6.82%	No	174,953	-	174,953	7,503,020	-	-	7,503,020	179,735	-	179,735	-	7,708,087	-	7,708,087
Foreign	Edelnor	Peru	Foreign	AFP Prima	Peru	Sol	7.13%	7.00%	No	15,778	-	15,778	-	4,689,387	-	4,689,387	16,209	-	16,209	-	4,817,554	-	4,817,554
Foreign	Edelnor	Peru	Foreign	AFP Prima	Peru	Sol	7.44%	7.30%	No	167,411	-	167,411	-	-	5,627,265	5,627,265	171,987	-	171,987	-	-	5,781,065	5,781,065
Foreign	Edelnor	Peru	Foreign	AFP Profuturo	Peru	Sol	5.77%	5.69%	No	-	-	-	-	-	-	-	3,897,275	-	3,897,275	-	-	-	-
Foreign	Edelnor	Peru	Foreign	AFP Profuturo	Peru	Sol	6.67%	6.56%	No	-	-	-	-	-	-	-	5,894,881	-	5,894,881	-	-	-	-
Foreign	Edelnor	Peru	Foreign	AFP Profuturo	Peru	Sol	7.56%	7.42%	No	-	2,836,092	2,836,092	-	-	-	-	23,074	-	23,074	2,890,532	-	-	2,890,532

F-69


Taxpayer ID No. (RUT)	Company	Country	ID No. Financial Institution	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Secured/ Unsecured	12-2012							12-2011
										Current ThCh$			Non-current ThCh$				Current ThCh$			Non-current ThCh$
										Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non-current	Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non-current
Foreign	Edelnor	Peru	Foreign	AFP Profuturo	Peru	Sol	7.72%	7.58%	No	-	5,831,170	5,831,170	-	-	-	-	209,478	-	209,478	5,781,065	-	-	5,781,065
Foreign	Edelnor	Peru	Foreign	AFP Profuturo	Peru	Sol	7.91%	7.76%	No	205,151	5,627,265	5,832,416	-	-	-	-	210,758	-	210,758	5,781,065	-	-	5,781,065
Foreign	Edelnor	Peru	Foreign	AFP Profuturo	Peru	Sol	7.97%	7.81%	No	-	-	-	-	-	-	-	5,082,940	-	5,082,940	-	-	-	-
Foreign	Edelnor	Peru	Foreign	AFP Profuturo	Peru	Sol	8.06%	7.91%	No	111,970	-	111,970	4,672,505	-	-	4,672,505	115,030	-	115,030	-	4,800,211	-	4,800,211
Foreign	Edelnor	Peru	Foreign	AFP Profuturo	Peru	Sol	8.31%	8.15%	No	-	-	-	-	-	-	-	2,516,119	-	2,516,119	-	-	-	-
Foreign	Edelnor	Peru	Foreign	FCR - Macrofondo	Peru	Sol	9.92%	6.50%	No	-	-	-	-	-	-	-	4,840	-	4,840	-	-	-	-
Foreign	Edelnor	Peru	Foreign	FCR - Macrofondo	Peru	Sol	6.66%	6.55%	No	-	2,857,332	2,857,332	-	-	-	-	44,894	-	44,894	2,890,532	-	-	2,890,532
Foreign	Edelnor	Peru	Foreign	FCR - Macrofondo	Peru	Sol	7.03%	6.91%	No	121,631	-	121,631	-	-	3,751,510	3,751,510	124,955	-	124,955	-	-	3,854,043	3,854,043
Foreign	Edelnor	Peru	Foreign	Retirement Insurance Fund for Non-commissioned Officers and Specialists - Fosersoe	Peru	Sol	8.75%	8.57%	No	-	27,355	27,355	5,627,265	-	-	5,627,265	28,102	-	28,102	-	5,781,065	-	5,781,065
Foreign	Edelnor	Peru	Foreign	Mapfre Peru Cia de Seguros	Peru	Sol	6.28%	6.19%	No	79,202	3,751,510	3,830,712	-	-	-	-	81,366	-	81,366	3,854,043	-	-	3,854,043
Foreign	Edelnor	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	Sol	5.44%	5.37%	No	-	53,336	53,336	4,753,112	-	-	4,753,112	48,852	-	48,852	4,756,410	-	-	4,756,410
Foreign	Edelnor	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	Sol	6.50%	6.40%	No	-	17,985	17,985	4,743,193	-	-	4,743,193	17,997	-	17,997	4,746,484	-	-	4,746,484
Foreign	Edelnor	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	Sol	6.50%	6.40%	No	-	39,287	39,287	-	3,751,510	-	3,751,510	40,360	-	40,360	-	-	3,854,043	3,854,043
Foreign	Edelnor	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	Sol	7.06%	6.94%	No	-	82,797	82,797	-	5,627,265	-	5,627,265	85,060	-	85,060	-	-	5,781,065	5,781,065
Foreign	Edelnor	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	Sol	5.00%	4.94%	No	-	55,231	55,231	-	-	7,503,020	7,503,020	-	-	-	-	-	-	-
Foreign	Edelnor	Peru	Foreign	Essalud Health Insurance	Peru	Sol	7.84%	7.70%	No	28,609	750,302	778,911	-	-	-	-	29,390	-	29,390	770,809	-	-	770,809
Foreign	Edesur S.A.	Argentina	Foreign	oeds7	Argentina	Ar$	12.28%	11.75%	No	-	-	-	-	-	-	-	15,571	3,963,560	3,979,131	-	-	-	-
94,271,000-3	Enersis S.A.	Chile	97,004,000-5	Bonds UF 269	Chile	U.F.	7.02%	5.75%	No	-	2,600,112	2,600,112	4,943,927	5,847,754	16,279,903	27,071,584	-	2,409,255	2,409,255	4,490,426	5,342,947	18,824,480	28,657,853
94,271,000-3	Enersis S.A.	Chile	Foreign	Yankee Bonds 2014	USA	US$	7.69%	7.38%	No	5,678,277	-	5,678,277	176,552,999	-	-	176,552,999	6,142,514	-	6,142,514	189,274,248	-	-	189,274,248
94,271,000-3	Enersis S.A.	Chile	Foreign	Yankee Bonds 2016	USA	US$	7.76%	7.40%	No	-	739,151	739,151	-	123,377,492	-	123,377,492	-	799,582	799,582	-	133,177,054	-	133,177,054
94,271,000-3	Enersis S.A.	Chile	Foreign	Yankee Bonds 2026	USA	US$	7.76%	6.60%	No	-	2,265	2,265	-	-	411,806	411,806	-	2,450	2,450	-	-	445,474	445,474
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	US$	6.57%	6.47%	No	130,640	-	130,640	-	-	4,783,175	4,783,175	141,895	-	141,895	-	-	5,195,251	5,195,251
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	Sol	6.41%	6.31%	No	-	7,400	7,400	-	-	4,689,388	4,689,388	-	7,603	7,603	-	-	4,817,555	4,817,555
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	Sol	6.38%	6.28%	No	144,821	-	144,821	-	-	4,689,388	4,689,388	148,780	-	148,780	-	-	4,817,555	4,817,555
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	Sol	6.86%	6.75%	No	84,409	-	84,409	3,751,510	-	-	3,751,510	86,706	-	86,706	3,854,084	-	-	3,854,084
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	Sol	6.61%	6.50%	No	4,775,750	-	4,775,750	-	-	-	-	-	33,597	33,597	4,817,555	-	-	4,817,555
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	Sol	6.54%	6.44%	No	-	4,722,091	4,722,091	-	-	-	-	-	15,958	15,958	4,817,555	-	-	4,817,555
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	Sol	6.74%	6.63%	No	-	4,704,921	4,704,921	-	-	-	-	88,723	-	88,723	4,817,555	-	-	4,817,555
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	Sol	6.70%	6.59%	No	109,867	-	109,867	5,308,387	-	-	5,308,387	112,871	-	112,871	5,453,472	-	-	5,453,472
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	US$	6.44%	6.34%	No	130,645	-	130,645	-	-	-	-	141,900	-	141,900	-	-	5,195,251	5,195,251
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	US$	9.20%	9.00%	No	-	55,795	55,795	4,649,246	-	4,783,175	9,432,421	-	60,597	60,597	5,049,784	-	-	5,049,784
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	US$	7.93%	7.78%	No	135,080	-	135,080	-	-	3,905,938	3,905,938	146,718	-	146,718	-	-	4,242,442	4,242,442
Foreign	Edegel S.A.A	Peru	Foreign	Banco Continental	Peru	US$	7.25%	7.13%	No	96,257	-	96,257	3,039,708	-	-	3,039,708	104,550	-	104,550	-	3,301,582	-	3,301,582
Foreign	Edegel S.A.A	Peru	Foreign	Banco Scotiabank	Peru	US$	6.74%	6.63%	No	145,239	-	145,239	-	4,783,175	-	4,783,175	157,752	-	157,752	-	5,195,251	-	5,195,251
Foreign	Edegel S.A.A	Peru	Foreign	Banco Scotiabank	Peru	US$	6.09%	6.00%	No	78,922	-	78,922	-	4,783,175	-	4,783,175	85,722	-	85,722	-	5,195,251	-	5,195,251
Foreign	Edegel S.A.A	Peru	Foreign	Banco Scotiabank	Peru	US$	5.87%	5.78%	No	69,132	-	69,132	-	-	4,783,175	4,783,175	75,088	-	75,088	-	-	5,195,251	5,195,251
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	A-10 Bonds	Colombia	CP	7.95%	7.72%	No	469,671	-	469,671	56,910,929	-	-	56,910,929	-	534,079	534,079	-	-	56,169,355	56,169,355
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	A102 Bonds	Colombia	CP	7.95%	7.72%	No	89,461	-	89,461	9,864,217	-	-	9,864,217	-	101,729	101,729	-	-	9,747,283	9,747,283
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	A5 Bonds	Colombia	CP	8.06%	8.06%	No	3,205,705	-	3,205,705	-	46,070,752	-	46,070,752	-	116,036	116,036	-	13,223,871	-	13,223,871
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	B09-09 Bonds	Colombia	CP	7.38%	7.19%	No	134,607	-	134,607	13,398,459	-	-	13,398,459	-	1,416,305	1,416,305	-	-	58,362,634	58,362,634
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	B10 Bonds	Colombia	CP	8.71%	8.44%	No	511,529	-	511,529	-	-	43,376,968	43,376,968	-	575,302	575,302	-	-	42,811,747	42,811,747
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	B-103 Bonds	Colombia	CP	9.03%	8.74%	No	183,657	-	183,657	-	-	15,040,745	15,040,745	-	3,654,924	3,654,924	-	-	45,470,431	45,470,431
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	B12 Bonds	Colombia	CP	9.27%	9.27%	No	1,161,554	-	1,161,554	24,992,028	-	-	24,992,028	-	592,993	592,993	-	-	23,960,242	23,960,242
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	B15 Bonds	Colombia	CP	8.83%	8.56%	No	1,261,346	-	1,261,346	-	-	59,133,165	59,133,165	-	205,704	205,704	-	-	14,844,758	14,844,758
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	E5-09 Bonds	Colombia	CP	9.04%	8.75%	No	529,504	-	529,504	-	-	24,276,576	24,276,576	-	1,146,419	1,146,419	-	24,666,371	-	24,666,371
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Foreign Bonds	Colombia	CP	10.17%	10.17%	No	2,318,404	-	2,318,404	-	-	24,390,398	24,390,398	-	2,288,195	2,288,195	-	-	24,072,581	24,072,581
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Quimbo Bonds	Colombia	CP	10.17%	10.17%	No	16,660,570	-	16,660,570	-	-	175,274,820	175,274,820	-	16,443,475	16,443,475	-	-	172,990,913	172,990,913
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	B10 Quimbo Bonds	Colombia	CP	6.39%	6.24%	No	264,062	-	264,062	-	-	81,301,327	81,301,327	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	B15 Quimbo Bonds	Colombia	CP	6.39%	6.24%	No	179,360	-	179,360	-	-	54,200,884	54,200,884	-	-	-	-	-	-	-

F-70


Taxpayer ID No. (RUT)	Company	Country	ID No. Financial Institution	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Secured/ Unsecured	12-2012														12-2011
										Current ThCh$						Non-current ThCh$								Current ThCh$						Non-current ThCh$
										Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non-current		Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non-current
91,081,000-6	Endesa S.A. (Chile)	Chile	97,004,000-5	Banco Santander Chile 317 Series-H	Chile	U.F.	7.17%	6.20%	No		-		5,731,907		5,731,907		9,501,752		9,501,752		48,775,725		67,7709,229		-		5,653,703		5,653,703		9,274,316		9,274,316		51,798,587		70,347,219
91,081,000-6	Endesa S.A. (Chile)	Chile	97,004,000-5	Banco Santander Chile 522 Series-M	Chile	U.F.	4.82%	4.75%	No		-		446,803		446,803		-		-		224,665,832		224,665,832		-		436,109		436,109		-		-		218,509,846		218,509,846
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	The Bank of New York Mellon – 144 - A	USA	US$	8.50%	8.35%	No		6,679,443		191,984,000		198,663,443		-		-		-		-		7,225,533		-		7,225,533		206,726,825		-		-		206,726,825
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	The Bank of New York Mellon – 144 - A	USA	US$	8.83%	8.63%	No		3,449,713		-		3,449,713		94,914,421		-		-		94,914,421		3,731,750		-		3,731,750		-		102,843,263		-		102,843,263
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	The Bank of New York Mellon –First Issue S-1	USA	US$	7.96%	7.88%	No		3,242,355		-		3,242,355		-		-		97,491,553		97,491,553		3,507,440		-		3,507,440		-		-		105,516,202		105,516,202
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	The Bank of New York Mellon –First Issue S-2	USA	US$	7.40%	7.33%	No		1,036,841		-		1,036,841		-		-		33,456,554		33,456,554		1,121,609		-		1,121,609		-		-		36,254,989		36,254,989
91,081,000-6	Endesa S.A. (Chile)	Chile	Foreign	The Bank of New York Mellon –First Issue S-3	USA	US$	8.26%	8.13%	No		656,705		-		656,705		-		-		13,944,705		13,944,705		710,395		-		710,395		-		-		15,584,934		15,584,934
91,081,000-6	Endesa S.A. (Chile)	Chile	97,004,000-5	Banco Santander Chile - 264 Series-F	Chile	U.F.	6.44%	6.44%	No		-		-		-		-		-		-		-		31,548,592		-		31,548,592		-		-		-		-
91,081,000-6	Endesa S.A. (Chile)	Chile	97,004,000-5	Banco Santander Chile – 318 Series-K	Chile	U.F.	3.86%	3.86%	No		-		-		-		-		-		-		-		-		699,402		699,402		-		-		88,931,329		88,931,329

				Total Unsecured Bonds							85,104,909		309,285,047		394,389,956		594,697,243		517,556,213		1,092,454,842		2,204,708,298		91,218,618		151,567,139		242,785,757		687,373,937		503,771,010		1,248,768,956		2,439,913,303

Appendix No. 4, letter b) presents details of estimated future cash flows (undiscounted) that the Group will have to disburse to settle the secured and unsecured obligations detailed above.

F-71

- Detail of Financial Lease Obligations


Taxpayer ID No. (RUT)	Company	Country	ID No. Financial Institution	Financial Institution	Country	Currency	Nominal Interest Rate	12-2012														12-2011
								Current						Non-current								Current						Non-current
								Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non-current		Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non-current
Foreign	Edegel S.A.A.	Peru	Foreign	Banco Scotiabank	Peru	US$	2.13%		1,231,661		3,610,794		4,842,455		11,478,411		17,127,941		-		28,606,352		1,918,477		6,218,565		8,137,042		10,519,276		14,415,305		11,395,943		36,330,524
Foreign	Edelnor	Peru	Foreign	Banco BBVA Continental	Peru	Sol	5.77%		1,191,889		2,701,760		3,893,649		2,178,152						2,178,152		579,527		3,648,359		4,227,886		2,859,893		-		-		2,859,893
Foreign	Edesur S.A.	Argentina	Foreign	COMAFI	Argentina	Ar$	25.60%		72,637		390,074		462,711		202,235						202,235		121,499		280,084		401,583		593,623		-		-		593,623
91,081,000-6	Endesa S.A. (Chile)	Chile	87,509,100-K	Abengoa Chile	Chile	US$	6.50%		-		1,025,604		1,025,604		2,255,535		2,558,284		11,405,767		16,219,586		1,041,741		-		1,041,741		2,291,023		2,598,536		13,765,541		18,655,100

			Total Leasing						2,496,187		7,728,232		10,224,419		16,114,333		19,686,225		11,405,767		47,206,325		3,661,244		10,147,008		13,808,252		16,263,815		17,013,841		25,161,484		58,439,140

Appendix No. 4 letter c) presents details of estimated future cash flows (undiscounted) that the Group will have to disburse to settle the financial lease obligations detailed above.

- Detail of Other Obligations


Taxpayer ID No. (RUT)	Company	Country	ID No. Financial Institution	Financial Institution	Country	Currency				12-2012														12-2011
							Nominal			Current						Non-current								Current						Non-current
							Interest Rate			Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current		Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current
96,589,170-6	Empresa Eléctrica Pangue	Chile	N/A	Other	Chile	Ch$		N/A			-		-		-		-		-		-		-		2		-		2		-		-		-		-
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	N/A	Other	Chile	Ch$		N/A			-		-		-		-		-		-		-		27		-		27		-		-		-		-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Mitsubishi (secured debt)	Argentina	US$		7.42	%		70,025,348		-		70,025,348		-		-		-		-		7,749,998		14,969,290		22,719,288		12,851,153		37,735,332		-		50,586,485
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Mitsubishi (unsecured debt)	Argentina	US$		7.42	%		14,355,259		-		14,355,259		-		-		-		-		-		13,925,511		13,925,511		-		-		-		-
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Other	Argentina	Ar$		17.29	%		1,791,317		3,600,814		5,392,131		5,629,544		-		-		5,629,544		679,866		1,133,110		1,812,976		-		-		-		-
96,827,970-K	Endesa Eco S.A.	Chile	96,601,250-1	Inversiones Centinela S.A.	Chile	US$		6.10	%		2,022,260		-		2,022,260		-		-		-		-		3,929,271		-		3,929,271		-		-		-		-
96,830,980-3	Inversiones Gas Atacama Holding Ltda.	Chile	96,963,440-6	SC GROUP	Chile	US$		7.50	%		6,651,792		-		6,651,792		-		-		-		-		11,197,341		-		11,197,341		-		-		-		-
Foreign	Ampla Energía E Servicios S.A.	Brazil	Foreign	Bndes	Brazil	Real		9.06	%		3,218,667		9,027,835		12,246,502		23,271,708		22,831,600		12,665,160		58,768,468		4,941,520		10,526,077		15,467,597		23,343,601		22,203,629		22.367.250		67,914,480
Foreign	Ampla Energía E Servicios S.A.	Brazil	Foreign	Eletrobrás	Brazil	Real		6.50	%		172,980		640,394		813,374		2,375,163		2,224,100		1,703,248		6,302,511		205,853		613,419		819,272		2,035,832		2,239,892		2.816.907		7,092,631
96,800,570-7	Chilectra S.A.	Chile	N/A	Other	Chile	Ch$		N/A			-		-		-		-		-		-		-		-		1,235		1,235		-		-		-		-
94,271,000-3	Enersis S.A.	Chile	N/A	Other	Chile	Ch$		N/A			-		-		-		-		-		-		-		-		3,958		3,958		-		-		-		-
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Banco do Brasil	Brazil	Real		15.61	%		977,200		2,940,005		3,917,205		910,845		-		-		910,845		1,049,301		3,073,192		4,122,493		5,366,340		-		-		5,366,340
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Banco do Brasil	Brazil	US$		4.62	%		13,741		66,375		80,116		33,187		-		1,325,728		1,358,915		16,411		113,158		129,569		108,803		-		1.448.799		1,557,602
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Banco do Nordeste	Brazil	Real		7.78	%		1,524,427		6,381,892		7,906,319		19,261,134		9,944,359		6,165,602		35,371,095		1,975,303		6,454,541		8,429,844		24,074,744		5,911,192		6.650.091		36,636,027
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	BEI	Brazil	US$		5.49	%		-		-		-		-		-		-		-		-		4,532,108		4,532,108		-		-		-		-
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	BNDES	Brazil	Real		9.52	%		3,493,261		8,605,380		12,098,641		11,473,840		-		-		11,473,840		5,567,428		16,072,830		21,640,258		27,967,533		-		-		27,967,533
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Eletrobras	Brazil	Real		6.46	%		867,551		2,252,314		3,119,865		5,005,894		4,687,321		7,797,798		17,491,013		1,289,715		3,067,631		4,357,346		6,534,103		5,634,274		11.052.898		23,221,275
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Faelce	Brazil	Real		13.22	%		-		2,826,796		2,826,796		1,413,400		-		-		1,413,400		-		3,176,291		3,176,291		4,764,438		-		-		4,764,438

			Total Other								105,113,803		36,341,805		141,455,608		69,374,715		39,687,380		29,657,536		138,719,631		38,602,036		77,662,351		116,264,387		107,046,547		73,724,319		44,335,945		225,106,811

Appendix No. 4 letter d) presents details of estimated future cash flows (undiscounted) that the Group will have to disburse to settle these Other Obligations.

F-72

18.4 Hedged

debt

Of Enersis’ US dollar denominated debt, as of December 31, 2012, ThCh$ 663,941,768 is related to future cash flow hedges for the Group’s US dollar-linked operating income (see Note 3.m). As of December 31, 2011, this amount totaled ThCh$ 739,686,386.

The following table details changes in “Reserve of cash flow hedges” during 2012, 2011, and 2010 due to exchange differences of this debt:


	12-31-2012	12-31-2011	12-31-2010
Balance in hedging reserves (hedging income) at the beginning of the period, net	30,554,503	67,748,527	60,346,205
Foreign currency exchange differences recorded in equity, net	17,591,453	(28,520,464)	15,654,909
Recognition of foreign currency exchange differences in profit or loss, net	(10,657,638)	(9,306,698)	(8,252,587)
Foreign currency translation differences	(115,517)	633,136	-
Balance in hedging reserves (hedging income) at the end of the period, net	37,372,801	30,554,503	67,748,527

18.5 Other

information

As of December 31, 2012 and 2011, the Enersis Group has long-term lines of credit available for use amounting to ThCh$ 240,680,742 and ThCh$ 238,832,000, respectively.

19. RISK MANAGEMENT POLICY

The Group’s companies are exposed to certain risks that are managed by systems that identify, measure, limit concentration of, and monitor these risks.

The main principles in the Group’s risk management policy include the following:

Compliance with good corporate governance standards.

Strict compliance with all the Group’s internal policies.

The Group’s Risk Committee is the organization in charge of defining, approving, and updating the basic principles that are to inspire actions taken regarding risk.

Risk Governance is organized operationally through the Risk Control and Risk Management areas, which are two independent functions.

Each business and corporate area determines:

The markets and product areas in which it can operate based on its knowledge and ability to ensure effective risk management.

II.

Criteria regarding counterparts.

III.

Authorized operators.

Business and corporate areas establish their risk tolerance in a manner consistent with the defined strategy for each market in which they operate.

Business limits are ratified by the Group’s Risk Committee.

All of the operations of the businesses and corporate areas are conducted within the limits approved for each case.

Businesses, corporate areas, lines of business and companies design the risk management controls necessary to ensure that transactions in the markets are conducted in accordance with Enersis’ policies, standards, and procedures.

F-73

19.1. Interest rate risk

Changes in interest rates affect the fair value of assets and liabilities bearing fixed interest rates, as well as the expected future cash flows of assets and liabilities subject to floating interest rates.

The objective of managing interest rate risk exposure is to achieve a balance in the debt structure to minimize the cost of debt with reduced volatility in profit or loss.

In compliance with the current interest rate hedging policy, the proportion of fixed debt and/or hedged debt over the net total debt was 61% as of December 31, 2012.

Depending on the Group’s estimates and on the objectives of the debt structure, hedging transactions are performed by entering into derivatives contracts that mitigate interest rate risk. Derivative instruments currently used to comply with the risk management policy are interest rate swaps to set floating rate at fixed rate.

The financial debt structure of the Group detailed by fixed, hedged, and floating rate debt, net of hedging derivative instruments, is as follows:

Net position:


	12-31-2012 %			12-31-2011 %
Fixed interest rate		61	%		62	%
Floating interest rate		39	%		38	%
Total		100	%		100	%

19.2. Exchange

rate risk

Exchange rate risks involve basically the following transactions:

•

Debt taken on by the Group’s companies that is denominated in a currency other than that in which its cash flows are indexed.

•

Payments to be made for the acquisition of project-related materials in a currency other than that in which its cash flows are indexed.

•

Group company income directly linked to dollar changes.

•

Cash flows from foreign subsidiaries to the Chilean parent company which are exposed to exchange rate fluctuations.

In order to mitigate foreign currency risk, the Group’s foreign currency risk management policy is based on cash flows and includes maintaining a balance between U.S. dollar flows and the levels of assets and liabilities denominated in this currency. The objective is to minimize the exposure to variability in cash flows that are attributable to foreign exchange risk.

The hedging instruments currently being used to comply with the policy are currency swaps and forward exchange contracts. In addition, the policy seeks to refinance debt in the functional currency of each of the Group’s companies.

19.3. Commodities

risk

The Group has a risk exposure to price changes in certain commodities, basically due to:

•

Purchases of fuel used to generate electricity.

•

Energy purchase/sale transactions that take place in local markets.

In order to reduce the risk in situations of extreme drought, the company has designed a commercial policy that defines the levels of sales commitments in line with the capacity of its generating power plants in a dry year and includes risk mitigation terms in certain contracts with unregulated customers.

F-74

Considering the operating conditions faced by the power generation market in Chile, with drought and highly volatile commodity prices on international markets, the Group is constantly verifying the advisability of using hedging to lessen the impacts that these price swings have on its results. As of December 31, 2012, the Group has swap operations for 462,000 barrels of Brent crude oil for January 2013 and 365,000 tons of coal for February through June of 2013.

Depending on operating conditions, which are constantly being updated, these hedges may be modified or may cover other commodities (see Note 20.3).

19.4. Liquidity

risk

The Group maintains a liquidity risk management policy that consists of entering into long-term committed banking facilities and temporary financial investments for amounts that cover the projected needs over a period of time that is determined based on the situation and expectations for debt and capital markets.

The projected needs mentioned above include maturities of financial debt, net of financial derivatives. For further details regarding the features and conditions of financial obligations and financial derivatives, see Notes 18 and 20, and Appendix No. 4.

As of December 31, 2012, the Group has cash and cash equivalent totaling ThCh$ 857,380,018 and unconditionally available lines of long-term credit totaling ThCh$ 240,683,000. As of December 31, 2011, the Group had ThCh$ 1,219,921,268 in cash and cash equivalents and ThCh$ 238,832,000 in unconditionally available lines of long-term credit.

19.5. Credit

risk

Given the current economic situation, the Group has been conducting detailed monitoring of its credit risk.

Trade receivables:

The credit risk for receivables from the Group’s commercial activity has historically been very low, due to the short term period of collections from customers, resulting in non-significant cumulative receivables amounts. This situation applies to both the electricity generating and distribution lines of business.

In our electricity generating business, some countries’ regulations allow the suspension of energy service to customers with outstanding payments, and most contracts have termination clauses for payment default. The Company monitors its credit risk on an ongoing basis and measures quantitatively its maximum exposure to payment default risk, which, as stated above, is very low.

In our electricity distribution companies, the suspension of energy service for customers in payment default is permitted in all cases, in accordance with current regulations in each country. This facilitates our credit risk management, which is also low in this line of business.

Financial assets:

Cash surpluses are invested in the highest-rated local and foreign financial entities (with risk rating equivalent to investment grade) with thresholds established for each entity.

Banks that have received investment grade ratings from at least two of the three major international rating agencies (Moody’s, S&P, and Fitch) are selected for making investments.

Investments are backed with treasury bonds from the countries in which the company operates and/or with commercial papers issued by the highest rated banks; wherever possible and when market conditions permit, the treasury bonds are preferred.

Derivative instruments are entered into with entities with solid creditworthiness; all derivative transactions are performed with entities with investment grade ratings.

F-75

19.6. Risk

measurement

The Enersis Group measures the Value at Risk (VaR) of its debt positions and financial derivatives in order to ensure that the risk assumed by the company remains consistent with the risk exposure defined by Management, thereby reducing volatility in the income statement.

The portfolio of positions included in calculating the current Value at Risk consists of the following:

•

Debt

•

Financial derivatives.

The VaR determined represents the potential loss in value of the portfolio of positions described above in one day with a 95% confidence level. To determine the VaR, we take into account the volatility of the risk variables affecting the value of the portfolio of positions including:

•

U.S. dollar Libor interest rate.

•

The customary local indices used in the banking industry for debt, considering the various currencies in which our companies operate.

•

The Exchange rates of the various currencies used in the calculation.

The calculation of VaR is based on generating possible future scenarios (at one day) of market values (both spot and term) for the risk variables, using Bootstrapping simulations. The number of scenarios generated ensures compliance with the simulation convergence criteria. The table of volatilities and correlations between the various risk variables calculated based on the historical values of the logarithmic price return has been applied to simulate the future price scenario.

Once the price scenarios have been obtained, the fair value of the portfolio is calculated using such scenarios, thereby obtaining a distribution of possible values at one day. The one-day 95%-confidence VaR number is calculated as the 5% percentile of the potential increases in the fair value of the portfolio in one day.

The various debt positions and financial derivatives included in the calculation have been valued consistently using the financial capital calculation methodology reported to Management.

Taking into account the assumptions described above, the Value at Risk of the previously discussed positions, broken down by type of position, is shown in the following table:


Financial Positions	12-31-2012		12-31-2011
Financial Positions	ThCh$		ThCh$
Interest rate		16,015,372		41,560,004
Exchange rate		2,344,016		3,602,591
Correlation		(638,396)		(310,050)
Total		17,720,992		44,852,545

The Value at Risk positions have varied during the 2012 and 2011 fiscal years depending on the start/maturity of operations throughout each year.

F-76

20.

FINANCIAL INSTRUMENTS

20.1

Financial instruments, classified by type and category

The detail of financial assets, classified by type and category, as of December 31, 2012 and 2011 is as follows:


		December 31, 2012
	Financial assets held for trading ThCh$		Financial assets at fair value with change in net income ThCh$		Held-to- maturity investments ThCh$		Loans and receivables ThCh$		Available-for- sale financial assets ThCh$		Financial derivatives for hedging ThCh$

Derivative instruments		-		-		-		-		-		51,876
Other financial assets		-		194,196,327		-		902,486,072		-		-
Total Current		-		194,196,327		-		902,486,072		-		51,876

Equity instruments		-		-		-		-		2,882,792		-
Derivative instruments		-		-		-		-		-		32,384,466
Other financial assets		-		-		27,045,746		204,553,172		375,227,434		-
Total Non-Current		-		-		27,045,746		204,553,172		378,110,226		32,384,466

Total		-		194,196,327		27,045,746		1,107,039,244		378,110,226		32,436,342


		December 31, 2011
	Financial assets held for trading ThCh$		Financial assets at fair value with change in net income ThCh$		Held-to- maturity investments ThCh$		Loans and receivables ThCh$		Available-for- sale financial assets ThCh$		Financial derivatives for hedging ThCh$
Derivative instruments		47,504		-		-		-		-		748,078
Other financial assets		-		-		-		1,013,028,618		-		-
Total Current		47,504		-		-		1,013,028,618		-		748,078
Equity instruments		-		-		-		-		2,892,655		-
Derivative instruments		-		-		-		-		-		12,178,355
Other financial assets		-		-		20,793,960		444,818,541		-		-
Total Non-Current		-		-		20,793,960		444,818,541		2,892,655		12,178,355

Total		47,504		-		20,793,960		1,457,847,159		2,892,655		12,926,433

F-77

The detail of financial liabilities, classified by type and category, as of December 31, 2012 and 2011 is as follows:


		December 31, 2012
	Financial liabilities held for trading ThCh$		Financial liabilities at fair value with change in net income ThCh$		Loans and payables ThCh$		Financial derivatives for hedging ThCh$

Interest-bearing loans		3,755,999		2,022,260		659,553,195	-
Derivative instruments		-		-		-	4,850,754
Other financial liabilities		-		-		1,360,087,146	-
Total Current		3,755,999		2,022,260		2,019,640,341	4,850,754

Interest-bearing loans		8,336,860		-		2,686,414,838	-
Derivative instruments		-		-		-	233,368,171
Other financial liabilities		-		-		-	-
Total Non-Current		8,336,860		-		2,686,414,838	233,368,171

Total		12,092,859		2,022,260		4,706,055,179	238,218,925

		December 31, 2011
	Financial liabilities held for trading ThCh$		Financial liabilities at fair value with change in net income ThCh$		Loans and payables ThCh$		Financial derivatives for hedging ThCh$

Interest-bearing loans		11,601,335		3,929,271		646,444,125	-
Derivative instruments		807,105		-		-	6,200,643
Other financial liabilities		-		-		1,395,341,923	-
Total Current		12,408,440		3,929,271		2,041,786,048	6,200,643

Interest-bearing loans		13,215,469		-		3,035,982,494	-
Derivative instruments		-		-		-	212,913,735
Other financial liabilities		-		-		23,548,235	-
Total Non-Current		13,215,469		-		3,059,530,729	212,913,735

Total		25,623,909		3,929,271		5,101,316,777	219,114,378

20.2

Derivative instruments

The risk management policy of the Group uses primarily interest rate and foreign exchange rate derivatives to hedge its exposure to interest rate and foreign currency risks.

The Company classifies its hedges as follows:

Cash flow hedges: Those that hedge the cash flows of the underlying hedged item.

Fair value hedges: Those that hedge the fair value of the underlying hedged item.

Non-hedge derivatives: Financial derivatives that do not meet the requirements established by IFRS to be designated as hedge instruments are recorded at fair value with changes in net income (assets held for trading).

F-78

Assets and liabilities for hedge derivative instruments

As of December 31, 2012 and 2011, financial derivative transactions qualifying as hedge instruments resulted in recognition of the following assets and liabilities in the statement of financial position:


		December 31, 2012								December 31, 2011
		Assets				Liabilities				Assets				Liabilities
	Current ThCh$		Non-current ThCh$		Current ThCh$		Non-current ThCh$		Current ThCh$		Non-current ThCh$		Current ThCh$		Non-current ThCh$
Interest rate hedge:		-		3,183,912		184,337		5,583,530		-		2,792,448		119,964	7,048,868
Cash flow hedge		-		3,183,912		184,337		5,583,530		-		2,792,448		119,964	7,048,868
Exchange rate hedge:		51,876		29,200,554		4,666,417		227,784,641		748,078		9,385,907		6,080,679	205,864,867
Cash flow hedge		51,876		29,200,554		4,648,602		224,676,991		748,078		9,385,907		3,070,825	201,717,556
Fair value hedge		-		-		17,815		3,107,650		-		-		3,009,854	4,147,311
TOTAL		51,876		32,384,466		4,850,754		233,368,171		748,078		12,178,355		6,200,643	212,913,735

General information on Hedge Derivative Instruments

Hedge derivative instruments and their corresponding hedged instruments are shown in the following table:

Detail of Hedge Instruments

Description of

Hedge

Instrument

Description of Hedged Instrument

Fair Value of

Hedged

Instruments

12-31-2012

Fair Value of

Hedged

Instruments

12-31-2011

Type of

Risks

Hedged

SWAP

Interest rate

Bank borrowings

(2,583,955)

(4,376,384

)

Cash flow

SWAP

Exchange rate

Bank borrowings

(3,125,465)

(7,157,165

)

Fair value

SWAP

Exchange rate

Unsecured obligations (bonds)

(200,073,163)

(194,654,396

)

Cash flow

At the close of the 2012 and 2011 fiscal years, the Group has not recognized significant gains or losses for ineffective cash flow hedges.

For fair value hedges the gain or losses recognized on the hedging instrument and on the underlying hedged item is detailed in the following table:


		December 31, 2012				December 31, 2011				December 31, 2010
	Gains ThCh$		Losses ThCh$		Gains ThCh$		Losses ThCh$		Gains ThCh$		Losses ThCh$
Hedge instrument		381,011		-		4,034,969		-		3,788,165	-
Hedged item		-		2,167,393		-		4,763,189		-	6,749,098
TOTAL		381,011		2,167,393		4,034,969		4,763,189		3,788,165	6,749,098

Financial derivative instrument assets and liabilities at fair value with changes in net income

As of December 31, 2012 and 2011, financial derivative transactions recorded at fair value with changes in net income, resulted in the recognition of the following assets and liabilities in the statement of financial position:


	December 31, 2012				December 31, 2011
	Assets Current ThCh$	Liabilities Current ThCh$	Assets Non-current ThCh$	Liabilities Non-current ThCh$	Assets Current ThCh$	Liabilities Current ThCh$	Assets Non-current ThCh$	Liabilities Non-current ThCh$

Non-hedging derivative instruments	-	-	-	-	47,504	807,105	-	-

F-79

Other information on derivatives:

The following tables present the fair value of hedging and non-hedging derivatives entered into by the Group as well as the remaining contractual maturities as of December 31, 2012 and 2011:


		December 31, 2012
					Notional Value
Financial Derivatives	Fair Value ThCh$			Less than 1 Year ThCh$		1-2 Years ThCh$		2-3 Years ThCh$		3-4 Years ThCh$		4-5 Years ThCh$		More than 5 Years ThCh$		Total ThCh$

Interest rate hedge:		(2,583,955	)		6,587,265		117,831,384		33,525,893		43,789,494		20,679,250		-	222,413,286
Cash flow hedge		(2,583,955	)		6,587,265		117,831,384		33,525,893		43,789,494		20,679,250		-	222,413,286
Exchange rate hedge:		(203,198,628	)		10,905,551		490,286,790		1,785,653		216,342,351		-		-	719,320,345
Cash flow hedge		(200,073,163	)		9,407,392		488,681,512		65,598		216,342,351		-		-	714,496,853
Fair value hedge		(3,125,465	)		1,498,159		1,605,278		1,720,055		-		-		-	4,823,492
Derivatives not designated for hedge accounting		-			-		-		-		-		-		-	-

TOTAL		(205,782,583	)		17,492,816		608,118,174		35,311,546		260,131,845		20,679,250		-	941,733,631

		December 31, 2011
					Notional Value
Financial Derivatives	Fair Value ThCh$			Less than 1 Year ThCh$		1-2 Years ThCh$		2-3 Years ThCh$		3-4 Years ThCh$		4-5 Years ThCh$		More than 5 Years ThCh$		Total ThCh$

Interest rate hedge:		(4,376,384	)		10,780,523		7,125,818		125,247,877		6,893,698		5,292,723		8,368,224	163,708,863
Cash flow hedge		(4,376,384	)		10,780,523		7,125,818		125,247,877		6,893,698		5,292,723		8,368,224	163,708,863
Exchange rate hedge:		(201,811,561	)		29,287,450		10,912,595		499,430,704		2,091,618		211,163,933		-	752,886,300
Cash flow hedge		(194,654,396	)		23,473,223		9,147,062		497,538,936		64,588		211,163,933		-	741,387,742
Fair value hedge		(7,157,165	)		5,814,227		1,765,533		1,891,768		2,027,030		-		-	11,498,558
Derivatives not designated for hedge accounting		(759,601	)		17,569,294		-		-		-		-		-	17,569,294

TOTAL		(206,947,546	)		57,637,267		18,038,413		624,678,581		8,985,316		216,456,656		8,368,224	934,164,457

The hedging and non-hedging derivatives contractual maturities do not represent the total Group’s risk exposure, as the amounts presented in the above tables have been drawn up based on undiscounted contractual cash inflows and outflows for their settlement.

F-80

20.3 Fair value hierarchies

Financial instruments recognized at fair value in the consolidated statement of financial position are classified based on the hierarchies described in Note 3.g.5.

The following table presents financial assets and liabilities measured at fair value as of December 31, 2012 and 2011:


Financial Instruments Measured at Fair Value		Fair Value Measured at End of Reporting Period Using:
	12-31-2012		Level 1	Level 2	Level 3
	ThCh$		ThCh$	ThCh$	ThCh$
Financial Assets
Financial derivatives designated as cash flow hedge	32,436,342		-	32,436,342	-
Commodity derivatives designated as cash flow hedge	784,741		-	784,741	-
Financial assets at fair value with change in net income)	194,196,327		194,196,327	-	-
Available-for-sale financial assets, non-current	31,468		31,468	-	-
Total	227,448,878		194,227,795	33,221,083	-
Financial Liabilities
Financial derivatives designated as cash flow hedge	235,093,460		-	235,093,460	-
Financial derivatives designated as fair value hedge	3,125,465		-	3,125,465	-
Commodity derivatives designated as cash flow hedge	32,200		-	32,200	-
Interest-bearing borrowings, short term	3,755,999		-	3,755,999	-
Interest-bearing borrowings, long term	8,336,860		-	8,336,860	-
Other short term financial liabilities	2,022,260		-	-	2,022,260
Total	252,366,244		-	250,343,984	2,022,260


Financial Instruments Measured at Fair Value		Fair Value Measured at End of Reporting Period Using:
	12-31-2011		Level 1	Level 2	Level 3
	ThCh$		ThCh$	ThCh$	ThCh$
Financial Assets
Financial derivatives designated as cash flow hedge	12,926,433		-	12,926,433	-
Financial derivatives not designated for hedge accounting	47,504		-	47,504	-
Available-for-sale financial assets, non-current	86,852		86,852	-	-
Total	13,060,789		86,852	12,973,937	-
Financial Liabilities
Financial derivatives designated as cash flow hedge	211,957,213		-	211,957,213	-
Financial derivatives designated as fair value hedge	7,157,165		-	7,157,165	-
Commodity derivatives designated as cash flow hedge	807,105		-	807,105	-
Interest-bearing borrowings, short term	11,601,335		-	11,601,335	-
Interest-bearing borrowings, long term	13,215,469		-	13,215,469	-
Other short-term financial liabilities	3,929,271		-	-	3,929,271
Total	248,667,558		-	244,738,287	3,929,271

20.3.1

The following is the reconciliation between opening and closing balances for financial instruments whose fair value is classified at level 3:


Non-current Interest-bearing Borrowings		ThCh$
Balance at December 31, 2010		12,395,250
Total profit recognized in financial profit or loss		(8,465,979)
Balance at December 31, 2011		3,929,271
Total profit recognized in financial profit or loss		(1,907,011)
Balance at December 31, 2012		2,022,260

The fair value of Level 3 has been calculated by applying a traditional discounted cash flow method. These projected cash flows include assumptions from within the company that are primarily based on estimates for prices and levels of energy production and firm capacity, as well as the costs of operating and maintaining some of our plants.

None of the possible reasonable scenarios foreseeable in the assumptions mentioned in the above paragraph would result in a significant change in the fair value of the financial instruments included at this level.

For the information about the available for sale financial instrument related to indemnity to be received at the end of the period of concessions of Ampla an Coelce, see note 6.

F-81

21.

TRADE AND OTHER PAYABLES

The breakdown of Trade and other payables as of December 31, 2012 and 2011 is as follows:

Current

Non-current

12-31-2012

12-31-2011

12-31-2012

12-31-2011

Trade and Other Payables

ThCh$

Trade payables

414,477,338

393,066,581

Other payables

798,782,397

841,997,878

14,257,438

14,304,607

Total

1,213,259,735

1,235,064,459

14,257,438

14,304,607

The detail of Trade Accounts and other Payables as of December 31, 2012 and 2011 is as follows:


	Current				Non-current One to five years
Trade Accounts and Other Payables	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$
Energy suppliers		367,620,139		354,964,500		-	-
Fuel and gas suppliers		46,857,199		38,102,081		-	-
Payables for goods and services		537,415,415		529,596,153		24,806	243,790
Dividends payable to third parties		117,318,367		161,073,860		-	-
Fines and complaints (*)		78,970,305		74,994,982		-	-
Research and development		24,036,804		17,971,576		7,544,852	3,894,943
Payables to tax authorities		5,416,568		17,684,946		4,151,439	7,580,699
Mitsubishi contract (LTSA)		16,988,406		11,514,861		-	-
Obligations for social programs		3,663,538		14,987,123		-	-
Other accounts payable		14,972,994		14,174,377		2,536,341	2,585,175
Total		1,213,259,735		1,235,064,459		14,257,438	14,304,607

See Note 19.4 for the description of the liquidity risk management policy.

(*) This corresponds to fines and complaints our Argentine subsidiary Edesur S.A. has received from the regulatory agency due to business service quality, technical product quality, and public safety prior to 2010. These fines have not been paid, as some were suspended under the Agreement Act signed in 2007 with the Argentine government, and others are pending until the Integral Tariff Review (ITR) takes place (see Note 4.2).

22.

PROVISIONS

The breakdown of provisions as of December 31, 2012 and 2011 is as follows:


Provisions	Current				Non-current
	12-31-2012		12-31-2011		12-31-2012		12-31-2011
	ThCh$		ThCh$		ThCh$		ThCh$

Provision for legal proceedings		31,476,623		49,741,677		156,269,126	186,849,932
Decommissioning, restoration, and rehabilitation costs		-		-		20,612,156	13,806,632
Provision for suppliers and services		11,635,899		9,689,600		-	-
Provision for employee benefits		27,311,499		31,162,406		100,707	65,221
Risk provisions		-		-		-	38,388
Other provisions		20,706,674		9,108,971		97,000	1,813,468

Total		91,130,695		99,702,654		177,078,989	202,573,641

F-82

Changes in provisions as of December 31, 2012 and 2011 is as follows:


	Warranty			Legal Proceedings			Decommissioning, Restoration, and Rehabilitation Costs			Other Provisions			Total
		ThCh$			ThCh$			ThCh$			ThCh$		ThCh$
Changes in Provisions
Opening balance at January 1, 2012		-			236,591,609			13,806,632			51,878,054		302,276,295
Additional provisions		-			-			6,293,131			-		6,293,131
Increase (Decrease) in existing provisions		-			(10,979,847	)		2,890			1,732,867		(9,244,090)
Provisions used		-			(35,949,989	)		(112,792	)		(18,253,231	)	(54,316,012)
Increase from adjustment to value of money over time		-			26,299,019			368,411			20,531,128		47,198,558
Foreign currency translation		-			(28,538,459	)		210,754			(7,091,382	)	(35,419,087)
Other increase (decrease)		-			323,416			43,130			11,054,343		11,420,889
Total changes in provisions		-			(48,845,860	)		6,805,524			7,973,725		(34,066,611)
Balance at December 31, 2012		-			187,745,749			20,612,156			59,851,779		268,209,684

	Warranty			Legal Proceedings			Decommissioning, Restoration, and Rehabilitation Costs			Other Provisions			Total
		ThCh$			ThCh$			ThCh$			ThCh$		ThCh$
Changes in Provisions
Opening balance at January 1, 2011		2,821,692			254,643,245			10,779,096			72,727,532		340,971,565
Additional provisions		-			-			2,049,816			-		2,049,816
Increase (Decrease) in existing provisions		-			36,123,460			54,806			2,684,365		38,862,631
Provisions used		-			(43,482,537	)		-			(14,019,715	)	(57,502,252)
Unused provisions reversed		-			(69,128,722	)		-			-		(69,128,722)
Increase from adjustment to value of money over time		-			28,730,776			393,141			7,779,422		36,903,339
Foreign currency translation		(38,273	)		(547,411	)		573,146			1,737,638		1,725,100
Other increase (decrease)		(2,783,419	)		30,252,798			(43,373	)		(19,031,188	)	8,394,818
Total changes in provisions		(2,821,692	)		(18,051,636	)		3,027,536			(20,849,478	)	(38,695,270)
Balance at December 31, 2011		-			236,591,609			13,806,632			51,878,054		302,276,295

23.

EMPLOYMENT BENEFIT OBLIGATIONS

23.1 General information

Enersis S.A. and certain of its subsidiaries in Chile, Brazil, Colombia, and Argentina provide various post-employment benefits for all or some of its active or retired employees. These benefits are calculated and recorded in the financial statements according to the criteria described in Note 3.l.1, and include primarily the following:

Defined benefits plans:

Complementary pension: The beneficiary is entitled to receive a monthly amount that supplements the pension obtained from the respective social security system.

Employee severance indemnities: The beneficiary receives a certain number of contractual salaries upon retirement. Such benefit is subject to a vesting minimum service requirement period, which depending on the company, varies within a range from 5 to 15 years.

Electricity: The beneficiary receives a monthly bonus to cover a portion of his/her billed residential electricity consumption.

Health benefit: The beneficiary receives health coverage in addition to that to which s/he is entitled under his/her social security regime.

F-83

Other benefits:

Five-year benefit: A benefit certain employees receive after 5 years; begins to accrue after the first year.

Unemployment: A benefit paid regardless of whether the employee is fired or leaves voluntarily. This benefit accrues on a daily basis and is paid at the time of contract termination (although the law allows for partial withdrawals for housing and education).

Seniority bonuses in Peru: There is an agreement to give workers (“subject to the collective agreement”) an extraordinary bonus for years of service upon completion of the equivalent of five years of actual work. This benefit is given according to the following scale:


After 5, 10, and 15 years	–	1 basic monthly salary
After 20 years	–	1 ¹/₂ basic monthly salaries
After 25, 30, 35, and 40 years	–	2 ¹/₂ basic monthly salaries

Defined contribution benefits:

The Group makes contributions to a retirement benefit plan where the beneficiary receives additional pension supplements upon his/her retirement, disability, or death.

23.2

Details, changes, and presentation in financial statements

The post-employment obligations associated with defined benefits plans and the related assets plan as of December 31, 2012 and 2011 are detailed as follows:

General ledger accounts:


	Balance at
	12-31-2012	12-31-2011
	ThCh$	ThCh$

Post-employment benefits, non-current	265,067,889	277,526,013

Total Liability	265,067,889	277,526,013

Total post-employment obligations, net	265,067,889	277,526,013

Reconciliation with general ledger accounts:
	Balance at
	12-31-2012	12-31-2011
	ThCh$	ThCh$

Post-employment obligations	637,730,012	600,384,950
(-) Fair value of asset plan (*)	(393,880,165)	(366,137,888)

Total	243,849,847	234,247,062

Amount not recognized as an asset due to limit on Defined Benefit Plan Assets	21,218,042	31,908,269
Minimum financing required (IFRIC 14) (**)	-	11,370,682

Total post-employment obligations, net	265,067,889	277,526,013

(*) Plan assets to fund defined benefit plans in our Brazilian subsidiaries (Ampla and Coelce) only; the remaining defined benefit plans in our other subsidiaries are unfunded.

(**) The Brazilian subsidiaries are subject to minimum funding requirements to cover the deficit from contributions committed to the sponsoring company.

F-84

The following table presents the balance recorded in the Consolidated Financial Situation Statement as a result of the difference between the actuarial liability from defined benefit commitments and the fair value of the assets affected as of December 31, 2012 and the close of the four previous fiscal years:


	12-31-2012	12-31-2011	12-31-2010	12-31-2009	12-31-2008
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Actuarial liability	637,730,012	600,384,950	554,990,745	510,334,175	443,320,261
Assets affected	(393,880,165)	(366,137,888)	(377,239,859)	(362,690,337)	(264,762,082)
Difference	243,849,847	234,247,062	177,750,886	147,643,838	178,558,179
Surplus limit from applying IFRIC 14 and Paragraph 58 (b) of IAS 19	21,218,042	43,278,951	42,952,266	39,960,319	2,126,401
Transfer to assets classified as held for sale	-	-	(2,786,493)	-	-
Accounting balance of actuarial liability deficit	265,067,889	277,526,013	217,916,659	187,604,157	180,684,580

The reconciliation of opening and closing balances of the defined benefit obligations as of December 31, 2012 and 2011:


Actuarial Value of Post-employment Obligations		ThCh$
Opening balance at January 1, 2011		554,990,745
Current service cost		4,355,454
Interest cost		57,048,714
Contributions from plan participants		1,252,638
Actuarial (gains) losses		31,390,546
Foreign currency translation		890,940
Benefits paid		(52,715,892)
Past service cost		4,385,031
Reduction of obligation from the sale of Cam and Synapsis		(2,885,053)
Other		1,671,827
Balance at December 31, 2011		600,384,950
Current service cost		3,103,256
Interest cost		54,464,782
Employee contributions		1,133,093
Actuarial (gains) losses		85,134,270
Foreign currency translation		(60,264,213)
Benefits paid		(47,235,456)
Past service cost		656,779
Others		352,551

Balance at December 31, 2012		637,730,012

As of December 31, 2012, out of the total amount of post-employment benefit obligations, 6.52% is from defined benefit plans in Chilean companies (5.99% at December 31, 2011); 77.69% is from defined benefit plans in Brazilian companies (78.56% at December 31, 2011); 14.29% is from defined benefit plans in Colombian companies (14.17% at December 31, 2011); 1.14% is from defined benefit plans in Argentine subsidiaries (1.28% at December 31, 2011); and the remaining 0.36% is from defined benefit plans in Peruvian companies.

F-85

Changes in the fair value of the benefit plan assets are as follows:


Fair Value of Benefit Plan Assets	ThCh$
Opening balance at January 1, 2011		(377,239,859	)
Expected return		(44,345,866	)
Actuarial (gains) losses		29,912,014
Foreign currency translation		5,214,769
Employer contributions		(13,605,383	)
Contributions paid		(1,252,638	)
Benefits paid		35,179,075
Balance at December 31, 2011		(366,137,888	)
Expected return		(34,379,133	)
Actuarial (gains) losses		(85,384,376	)
Foreign currency translation		73,137,727
Employer contributions		(1,133,093	)
Contributions paid		(11,477,878	)
Benefits paid		31,494,476

Balance at December 31, 2012		(393,880,165	)

The benefit plan assets invested in equity and the Group’s own properties are as follows:


	12-31-2012	12-31-2011
	ThCh$	ThCh$

Equity instruments	3	5
Real estate	12,825,725	10,152,936

Total	12,825,728	10,152,941

The main categories of benefit plan assets are as follows:


	12-31-2012		12-31-2011
Category of Benefit Plan Assets	ThCh$	%	ThCh$	%
Equity instruments (variable income)	52,904,778	13%	55,291,894	16%
Fixed income assets	295,967,203	75%	275,643,406	75%
Real estate investments	29,632,539	8%	20,653,101	6%
Other	15,375,645	4%	14,549,487	3%
Total	393,880,165	100%	366,137,888	100%

The expected rate of return on the benefit plan assets has been estimated considering the projections for financial markets of fixed and variable income instruments, and assuming that asset categories will have a weighting similar to that of the previous year. The average return on plan assets was 11.1% as of December 31, 2012.

The total expense recognized in profit or loss with respect to the defined benefit plans as of December 31 and 2012, 2011 and 2010 are as follows:


Expense Recognized in Profit or Loss	12-31-2012		12-31-2011		12-31-2010
		ThCh$		ThCh$	ThCh$
Normal service cost for defined benefits plan		3,103,256		4,355,454	4,455,159
Interest cost for defined benefits plan		54,464,782		57,048,714	52,703,379
Expected return on plan assets		(34,379,133)		(44,345,866)	(41,253,550)
Past service costs for defined benefits plan		656,779		4,385,031	-
Expenses recognized in Profit or Loss		23,845,684		21,443,333	15,904,988
Net actuarial (gains) losses		15,001,248		62,246,623	48,495,375
Total expense recognized in comprehensive income		38,846,932		83,689,956	64,400,363

F-86

23.3 Other disclosures

•

Actuarial assumptions:

As of December 31, 2012 and 2011, the following assumptions were used in the actuarial calculation of defined benefits:

Chile

Brazil

Colombia

Argentina

12-31-2012

12-31-2011

12-31-2012

12-31-2011

12-31-2012

12-31-2011

12-31-2012

12-31-2011

Discount rates used

6.00%

6.50%

9.98%

10.50%

8.00%

8.50%

5.50%

Expected return on plan assets

N/A

9.98%

11.10%

N/A

Expected rate of salary increases

3.00%

7.61%

6.59%

3.5% - 4.0%

- 4.5%

3.5% -4.0%

- 4.5%

0.00%

Mortality tables

RV -2004

RV-2004

AT 2000

RV 08

RV 2004

•

Sensitivity:

As of December 31, 2012, the sensitivity of the value of the actuarial liability for post-employment benefits to variations of 100 basis points in the discount rate assumes a decrease of ThCh$ 59,772,523 (ThCh$ 54,571,512 as of December 31, 2011) if the rate rises and an increase of ThCh$ 71,631,961 (ThCh$ 65,049,753 as of December 31, 2011) if the rate falls.

•

Defined contribution:

The total expense recognized in the consolidated statement of comprehensive income within line item “Employee expenses” represents contributions payables to the defined contribution plans by the Group. As of December 31, 2012, the amounts recognized as expenses were ThCh$ 2,092,037 (ThCh$ 1,998,189 as December 2011 and ThCh$ 1,382,818 at December 2010).

•

Future disbursements:

The estimates available indicate that ThCh$24,714,981 will be disbursed for defined benefit plans over the next 12 months.

24. EQUITY

24.1 Equity attributable to shareholders of Enersis

24.1.1 Subscribed and paid capital and number of shares

Enersis S.A.’s share capital as of December 31, 2012 and 2011 was ThCh$ 2,824,882,835, divided into 32,651,166,465 fully subscribed and paid no par value shares listed at the Bolsa de Comercio de Santiago de Chile, Bolsa Electrónica de Chile, Bolsa de Valores de Valparaíso, New York Stock Exchange (NYSE), and Bolsa de Valores Latinoamericanos de la Bolsa de Madrid (LATIBEX). There has been no change in the numbers of shares as of December 30, 2012 and December 31, 2011.

Capital contributions made in 2003 and 1995 resulted in share premiums amounting to ThCh$ 125,881,577 and ThCh$ 32,878,071, respectively. The Chilean Companies Law permits the use of the share premium account balance to increase capital and does not establish any specific restrictions as to its use.

24.1.2 Dividends

The Enersis Board of Directors, at the Board Meeting held on February 26, 2010, agreed to propose to the General Shareholders Meeting, to be held on April 22, 2010, the distribution of a final dividend equivalent to 35.11% of the Company’s 2009 net income, at Ch$ 7.1 per share.

The aforementioned proposal modified the Company’s dividend policy for 2009, which allowed for distribution of an expected final dividend of 60% of the Company’s net income. This was disclosed as an Essential Event dated February 26, 2010. In the General Ordinary Shareholders’ Meeting held on April 22, 2010, the shareholders agreed to distribute the minimum mandatory dividend and an additional dividend amounting to Ch$ 7.1 per share. This dividend was partially paid during 2009 (interim dividend No. 80) and the remaining Ch$ 4.64323 per share was paid on May 6, 2010 (final dividend No. 81).

The Board agreed to establish a dividend policy for 2010 amounting to 60% of 2010 net income.

F-87

The Enersis Board, at its Ordinary Session held on October 27, 2010, unanimously agreed to pay an interim dividend on January 27, 2011 of Ch$ 1.57180 per share out of 2010 net income and corresponding to 15% of the Company’s net income as of September 30, 2010.

At the Ordinary Shareholders’ Meeting held on April 26, 2011, it was unanimously agreed to pay a minimum obligatory dividend (partially paid through interim dividend No. 82) and an additional dividend totaling Ch$ 7.44578. Given that the interim dividend No. 82 had already been paid, distribution and payment of the balance of final dividend No. 83 totaling Ch$ 5.87398 per share was made from May 12, 2011 onwards.

The foregoing constitutes a modification to the Company’s 2010 dividend policy, which considered payment of the interim dividend in December.

The Enersis Board, at its Ordinary Session held on November 30, 2011, unanimously agreed to distribute an interim dividend of Ch$ 1.46560 per share on January 27, 2012 to be charged against the 2011 fiscal year net income; the amount to be distributed amounts to 15% of the liquid profits calculated as of September 30, 2011.

On February 29, 2012, the Enersis Board agreed, by a unanimous vote of the Directors present, to propose at the Enersis S.A. Ordinary Shareholders’ Meeting that the same percentage of profits be distributed as in the previous year, that is, 50% of the Company’s net profits. For this fiscal year, that percentage is the equivalent of Ch$ 5.7497 per share, from which the interim dividend of Ch$ 1.46560 per share paid in January 2012 will be deducted. Therefore, the final dividend amount distributed to shareholders will be Ch$ 4.2841 per Company share. This is a change from the previous dividend policy, which contemplated distributing 55% of the Company’s liquid profits in dividends.

At the Ordinary Shareholders Meeting held on April 26, 2012, it was agreed to distribute a minimum obligatory dividend (partially covered by interim dividend No. 84) and an additional dividend totaling Ch$ 5.74970. Since interim dividend 84 had already been paid, the remaining Ch$ 4.28410 per share was distributed and paid as final dividend No. 85.

Fulfillment of the aforementioned dividend plan is subject to the actual net income earned by the Company during the current year, and to the results of the Company’s periodic income projections or to the existence of certain conditions, as applicable.

On November 29, 2012, the Directors present at the meeting of the Board voted unanimously to distribute interim dividend 86 of Ch$ 1.21538 per share on January 25, 2013, to be charged against fiscal year 2012 results. This corresponds to 15% of the company’s net income calculated as of September 30, 2012, in accordance with the company’s current dividend policy.

The following table details the dividends paid in the last six years:


Dividend No.	Type of Dividend	Payment Date	Pesos per Share	Charged to
72	Final	04-20-2005	0.41654	2004
73	Final	04-03-2006	1.00000	2005
74	Interim	12-26-2006	1.11000	2006
75	Final	05-23-2007	4.89033	2006
76	Interim	12-27-2007	0.53119	2007
77	Final	04-30-2008	3.41256	2007
78	Interim	12-19-2008	1.53931	2008
79	Final	05-12-2009	4.56069	2008
80	Interim	12-17-2009	2.45677	2009
81	Final	05-06-2010	4.64323	2009
82	Interim	01-27-2011	1.57180	2010
83	Final	05-12-2011	5.87398	2010
84	Interim	01-27-2012	1.46560	2011
85	Final	05-09-2012	4.28410	2011
86	Interim	01-25-2013	1.21538	2012

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24.2 Foreign currency translation

The following table details translation adjustments, net of taxes and non-controlling interests, in the consolidated statement of financial position and the consolidated statement of change in equity as of December 31, 2012, 2011, and 2010:


	12-31-2012	12-31-2011	12-31-2010
Foreign Currency Translation	ThCh$	ThCh$	ThCh$
Empresa Distribuidora Sur S.A.	(68,251,285)	(72,109,861)	(71,531,480)
Ampla Energía E Serviços S.A.	52,686,506	125,398,489	131,368,333
Ampla Investimentos E Serviços S.A.	3,513,918	1,047,218	2,457,495
Compañía Distribuidora y Comercializadora de Energía S.A.	22,285,125	20,185,717	8,383,309
Edelnor	6,517,665	10,327,272	(10,033,638)
Investluz S.A.	(5,725,690)	3,630,372	3,645,236
Endesa Brasil S.A.	(104,168,848)	20,839,624	32,580,194
Central Costanera S.A.	(2,677,497)	(6,301,808)	(6,826,288)
Gas Atacama S.A.	(646,559)	3,979,726	(2,013,576)
Emgesa S.A. E.S.P.	53,834,515	51,141,069	38,858,582
Hidroelectrica El Chocon S.A.	(19,040,997)	(9,846,088)	(10,306,187)
Generandes Peru S.A.	24,592,212	28,938,192	766,900
Grupo Synapsis	-	-	(1,148,937)
Grupo CAM	-	-	(2,087,946)
Others	(3,639,124)	(607,254)	(833,107)
TOTAL	(40,720,059)	176,622,668	113,278,890

24.3 Capital management

The Company’s objective is to maintain an adequate level of capitalization in order to be able to secure its access to the financial markets, so as to fulfill its medium- and long-term goals while maximizing the return to its shareholders and maintaining a sound financial position.

24.4 Restrictions on subsidiaries’ transferring funds to the parent

Certain of the Group’s subsidiaries must comply with financial ratio covenants which require them to have a minimum level of equity or other requirements that restrict the transferring of assets to the Enersis. The Group’s restricted net assets as of December 31, 2012 from its subsidiaries Endesa Chile, Ampla Energía, Coelce, and Edelnor totaled ThCh$ 979,300,704, ThCh$ 351,933,559, ThCh$ 40,774,692, and ThCh$ 90,012,607, respectively.

F-89

24.5 Other reserves

Other reserves within Equity attributable as of shareholders of Enersis of December 31, 2012, 2011, and 2010 are as follows:


	Balance at January 1, 2012	Changes 2012	Balance at December 31, 2012
	ThCh$	ThCh$	ThCh$

Exchange differences on translation	176,622,668	(217,342,727)	(40,720,059)
Cash flow hedges	(310,265)	27,904,293	27,594,028
Remeasurement of available-for-sale financial assets	13,836	(189)	13,647
Miscellaneous other reserves	(1,497,208,996)	(801,373)	(1,498,010,369)
TOTAL	(1,320,882,757)	(190,239,996)	(1,511,122,753)

	Balance at January 1, 2011	Changes 2011	Balance at December 31, 2011
	ThCh$	ThCh$	ThCh$

Exchange differences on translation	113,278,890	63,343,778	176,622,668
Cash flow hedges	40,783,463	(41,093,728)	(310,265)
Remeasurement of available-for-sale financial assets	41,825	(27,989)	13,836
Miscellaneous other reserves	(1,505,891,534)	8,682,538	(1,497,208,996)
TOTAL	(1,351,787,356)	30,904,599	(1,320,882,757)

	Balance at January 1, 2010	Changes 2010	Balance at December 31, 2010
	ThCh$	ThCh$	ThCh$

Exchange differences on translation	196,973,210	(83,694,320)	113,278,890
Cash flow hedges	26,100,491	14,682,972	40,783,463
Remeasurement of available-for-sale financial assets	41,699	126	41,825
Miscellaneous other reserves	(1,505,891,534)	-	(1,505,891,534)
TOTAL	(1,282,776,134)	(69,011,222)	(1,351,787,356)

•

Translation reserves: These arise primarily from exchange differences relating to:

Translation of the financial statements of our foreign operations from their functional currencies to our presentation currency (i.e. Chilean peso) (see Note 2.6.3); and

Translation of goodwill arising from the acquisition of foreign operations with a functional currency other than the Chilean peso (see Note 3.c).

•

Cash flow hedging reserves:

These represent the cumulative portion of gains and losses on hedging instruments deemed effective in cash flow hedges (Note 3.g.4. and 3.m).

•

Other miscellaneous reserves

Other miscellaneous reserves include the following:

(i) In accordance with Official Bulletin No. 456 of the SVS, accumulated price level restatements related to paid-in capital since our transition to IFRS 1 on January 1, 2004 through December 31, 2008.

Note that despite the fact that the Company adopted IFRS as its accounting standards as of January 1, 2009, the January 1, 2004 transition date disclosed previously was that used by the our parent company Endesa, S.A. in its transition to IFRS. This applies the exemption provided for this purpose in IFRS 1, “First-time adoption.”

F-90

(ii) Translation differences existing at the date of transition to IFRS (exemption IFRS 1 “First-time adoption”).

(iii) Reserves arising from transactions between entities under common control, mainly explained by the creation of the Endesa Brasil Holding in 2005 and the merger of our Colombian subsidiaries Emgesa and Betania in 2007.

24.6 Non-controlling interests

The negative change reflected in the line item “Increase (decrease) from transfers and other changes” in the Statement of Changes in Net Equity is explained in the two periods primarily by non-controlling interests in the dividends declared by the consolidated companies.

24.7 Capital increase

At Enersis’ Extraordinary Shareholders’ Meeting held on December 20, 2012, a capital increase was approved by a very large majority of the shareholders with voting rights in attendance (86%), equivalent to 81.94% of the company’s total voting shares.

This capital increase has the following characteristics:

A total amount of Ch$ 2,844,397,889,381 (Chilean pesos) divided into 16,441,606,297 ordinary nominative shares, non-preferred, with no par value, and of a single series was approved.

Endesa España’s non-monetary contribution to Enersis will be for a total of Ch$ 1,724,400,000,034 corresponding to 9,967,630,058 Enersis shares at Ch$ 173 Chilean pesos per share.

The contribution from Minority interests was set at Ch$ 173 Chilean pesos per share to be issued as a result of this capital increase.

The shareholders approved the terms of the aforementioned capital increase as a related company operation under market conditions and in the best interests of the company, complying with the requirements of Law 18,046, Article 147.

F-91

25.

REVENUES

The detail of revenues presented in the Statement of Comprehensive Income for the periods ended December 31, 2012, 2011, and 2010 is as follows:


Revenues	Balance at
	12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$

Energy sales (1)	5,793,163,853	5,805,296,274	5,653,724,917

Other sales	20,348,542	31,746,174	50,570,774
Sale of metering equipment	2,588,881	2,229,019	2,621,293
Sale of products and services	17,759,661	29,517,155	47,949,481

Revenue from other services	446,796,834	417,209,641	474,934,133
Tolls and transmission	319,135,832	249,719,988	182,638,100
Metering equipment leases	4,653,801	6,540,680	9,646,546
Public lighting	32,613,523	27,583,293	31,092,463
Verifications and connections	13,653,352	15,605,137	14,106,659
Engineering and consulting services	17,620,795	11,896,382	39,313,843
Other services	59,119,531	105,864,161	198,136,522

Total operating revenue	6,260,309,229	6,254,252,089	6,179,229,824

Other Operating Income	Balance at
	12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$

Revenue from construction contracts	151,969,334	179,051,253	252,401,048
Mutual support	32,822,150	25,188,962	23,287,510
Third party services to own and third party fixtures	11,952,534	8,693,287	10,611,783
Leases	1,202,395	765,055	699,787
Sale of new businesses	12,824,744	12,619,489	11,380,343
Other revenue (2)	106,586,928	54,310,209	85,970,818

Total other income	317,358,085	280,628,255	384,351,289

(1) Includes ThCh$ 29,217,154 in 2012 from agreements corresponding to reconciliation, termination of arbitration, and settling of prices between Endesa Chile and CMPC.

(2) During the 2012 fiscal year, the Company recognized ThCh$ 2,239,336 (ThCh$ 7,273,992 in 2011 and ThCh$ 22,225,795 in 2010) related to the activation of the insurance policy covering the Central Bocamina I for business interruption, as well as ThCh$ 52,817,785 from the activation of the policy covering lost revenue from the Bocamina II Plant when that plant was not in operation (ALOP). Both were a consequence of the earthquake that occurred in Chile on February 27, 2010 and damaged those plants [see Note 15 d) vi)].

26.

RAW MATERIALS AND CONSUMABLES USED

Raw materials and consumables used presented in profit or loss for the periods December 31, 2012, 2011, and 2010 is as follows:


Raw Materials and Consumables Used	Balance at
	12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$

Energy purchases	(1,855,330,312)	(1,762,818,298)	(1,554,714,636)
Fuel consumption	(782,263,736)	(742,639,363)	(672,038,103)
Transportation costs	(469,848,829)	(393,991,121)	(405,983,092)
Costs from construction contracts	(151,969,334)	(179,051,253)	(252,401,048)
Other raw materials and consumables	(457,713,276)	(459,934,694)	(636,509,375)

Total	(3,717,125,487)	(3,538,434,729)	(3,521,646,254)

F-92

27.

EMPLOYEE BENEFITS EXPENSES

Employee expenses recognized in profit or loss for de periods December 31, 2012, 2011, and 2010 is as follows:


Employee Benefits Expense	Balance at
	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Wages and salaries		(301,116,418)		(277,553,004)		(295,339,462)
Post-employment benefit obligations expense		(5,852,072)		(6,353,643)		(5,837,977)
Social security and other contributions		(106,722,394)		(92,915,099)		(63,391,743)
Other employee expenses		(2,654,256)		(1,730,380)		(10,108,831)

Total		(416,345,140)		(378,552,126)		(374,678,013)

28.

DEPRECIATION, AMORTIZATION, AND IMPAIRMENT LOSSES

Depreciation, amortization, and impairment losses recognized in profit or loss for de periods December 31, 2012, 2011, and 2010 is as follows:

Balance at

12-31-2012
ThCh$

12-31-2011
ThCh$

12-31-2010

ThCh$

Depreciation

(340,383,481)

(322,218,490)

(338,040,266)

Amortization

(102,471,242)

(102,681,546)

(110,977,009)

Subtotal

(442,854,723)

(424,900,036)

(449,017,275)

Reversal (losses) from impairment (*)

(43,105,193)

(136,157,459)

(108,373,429)

Total

(485,959,916)

(561,057,495)

(557,390,704)


*() Impairment Losses**	Balance at
	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Financial assets (see Note 7c)		(33,173,360)		(18,649,480)		(95,391,111)
Assets and disposal groups held for sale (see Note 11)		-		-		(14,881,960)
Goodwill (see Note 14)		-		(14,379,823)		-
Infrastructure (see Note 15 x)		(12,578,098)		(106,449,843)		(1,340,235)
Reversal of provision for investment properties (see Note 16)		2,646,265		3,321,687		3,239,877

Total		(43,105,193)		(136,157,459)		(108,373,429)

F-93

29.

OTHER EXPENSES

Other miscellaneous operating expenses as of December 31, 2012, 2011, and 2010 is as follows:


Other Expenses	Balance at
	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Other supplies and services		(65,075,819)		(95,222,224)		(130,232,972)
Professional, outsourced, and other services		(213,336,835)		(180,880,189)		(113,944,110)
Repairs and maintenance		(93,522,392)		(89,045,849)		(69,199,458)
Indemnities and fines		(26,120,741)		(14,733,175)		(41,316,694)
Taxes and charges		(24,734,526)		(90,333,630)		(26,456,298)
Insurance premiums		(23,994,238)		(20,745,032)		(19,147,361)
Leases and rental costs		(18,905,120)		(17,042,089)		(16,980,825)
Marketing, public relations, and advertising		(7,991,376)		(10,316,261)		(16,207,055)
Other supplies		(23,758,539)		(10,929,579)		(9,240,977)
Travel expenses		(7,981,802)		(6,428,292)		(4,306,510)
Environmental expenses		(4,704,522)		(5,022,077)		(3,402,509)

Total		(510,125,910)		(540,698,397)		(450,434,769)

30.

OTHER GAINS (LOSSES)

Other gains (losses) as of December 31, 2012, 2011, and 2010 is as follows:


Other Gains (Losses)	Balance at
	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Investment sales, Cam Group and Synapsis (*)		-		(10,733,882)		272,686
Land sales		9,191,493		3,766,963		8,381,710
Other assets		5,639,981		2,152,625		3,329,038

Total		14,831,474		(4,814,294)		11,983,434

(*) Includes foreign currency translation differences of ThCh$ (3,236,883).

31.

FINANCIAL RESULTS

Financial income and costs as of December 31, 2012, 2011, and 2010 is as follows:


Financial Income	Balance at
	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Income from cash and cash equivalents		61,202,506		76,186,468		68,144,673
Income from expected return on plan assets (Brazil)		34,379,133		44,345,866		41,253,550
Other financial income		54,406,600		108,760,948		58,806,208
Income from other financial assets (1)		114,720,996		4,319,587		3,032,517

Total		264,709,235		233,612,869		171,236,948

F-94


Financial Costs	Balance at
	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Financial Costs		(453,447,437)		(465,411,363)		(438,358,251)

Bank loans		(43,179,075)		(57,873,580)		(64,983,625)
Secured and unsecured obligations		(204,574,008)		(212,931,127)		(193,181,616)
Financial leasing		(3,281,822)		(2,937,215)		(3,056,546)
Valuation of financial derivatives		(19,030,050)		(23,723,865)		(19,034,198)
Financial provisions		(47,191,100)		(35,959,378)		(21,006,595)
Post-employment benefit obligations		(54,464,782)		(57,048,714)		(52,703,379)
Capitalized borrowing costs		26,477,369		35,945,738		15,137,380
Other financial costs		(108,203,969)		(110,883,222)		(99,529,672)

*Gain (loss) from indexed assets and liabilities ()**		(12,681,628)		(25,092,203)		(15,055,706)

Foreign currency exchange differences, net ()**		(14,768,878)		20,305,690		11,572,474

Total Financial Costs		(480,897,943)		(470,197,876)		(441,841,483)

Total Financial Results		(216,188,708)		(236,585,007)		(270,604,535)

(1) Includes ThCh$ 112,274,835 in 2012 from reclassification and remeasured of the IFRIC 12 to financial investments (see Note 6).

The effects on Financial Results from exchange differences and the application of indexed assets and liabilities originated from the following:


*Results from Indexed Assets and Liabilities ()**	Balance at
	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Cash and cash equivalents		19,201		5,798		-
Other financial assets		5,629,466		8,659,909		5,270,820
Other non-financial assets		1,425		1,912		922,841
Trade and other accounts receivable		181,103		63,114		(391,383)
Current tax assets and liabilities		2,590,732		2,188,305		1,693,677
Other financial liabilities (financial debt and derivative instruments)		(21,849,406)		(35,864,236)		(22,386,567)
Trade and other accounts payable		272,244		159,833		146,406
Other provisions		(163,246)		(281,472)		(49,233)
Other non-financial liabilities		636,853		(25,366)		(262,267)

Total		(12,681,628)		(25,092,203)		(15,055,706)

Exchange Differences ()**	Balance at
	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Cash and cash equivalents		(2,517,811)		5,095,502		2,352,414
Other financial assets		6,021,281		6,146,671		15,284,485
Other non-financial assets		113,953		9,102,795		(3,281,851)
Trade and other accounts receivable		(1,712,212)		17,354,961		(14,400,873)
Current tax assets and liabilities		(4,910)		175,066		34,249
Other financial liabilities (financial debt and derivative instruments)		(17,196,956)		(11,293,585)		(373,873)
Trade and other accounts payable		1,353,385		(5,476,285)		15,576,463
Other non-financial liabilities		(825,608)		(799,435)		(3,618,540)

Total		(14,768,878)		20,305,690		11,572,474

F-95

32.

INCOME TAX

The following table reconciles income taxes resulting from applying the general current tax rate to “Net income before taxes” and the income tax expense recorded in the accompanying Consolidated Statement of Comprehensive Income for the 2012, 2011, and 2010 fiscal years:


Income Tax	Balance at
	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Current tax expense		(441,946,162)		(458,621,881)		(397,519,578)
Tax benefit from tax assets not previously recognized (credits and/or benefits on current tax)		68,352,902		42,545,139		51,094,799
Adjustments to current tax from the previous period		627,769		(882,687)		(2,869,081)
Other current tax expense		(988,028)		(301,441)		(2,597,705)

Current tax expense, net		(373,953,519)		(417,260,870)		(351,891,565)

Deferred tax income (expense)from origination and reversal of temporary differences		(28,092,513)		(43,612,506)		7,335,286
Deferred tax (income) or expense from tax rate changes or new taxes (*)		(9,845,202)		148,137		(1,450,689)
Other deferred tax expense		-		(111,453)		-

Deferred tax income (expense), net		(37,937,715)		(43,575,822)		5,884,597

Effect of changes in the tax status of the entity or its shareholders		-		-		-

Income tax income (expense)		(411,891,234)		(460,836,692)		(346,006,968)

The principal temporary differences are detailed in Note 17a.


Reconciliation of Tax Expense	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$

Tax expense using statutory rate (20%)		(261,090,642)		(266,675,462)		(245,938,215)
Tax effect of rates in other jurisdictions		(137,437,336)		(117,057,673)		(159,695,526)
Tax effect of non-taxable revenues		75,083,835		51,007,579		44,357,904
Tax effect of non-tax-deductible expenses		(117,963,860)		(106,636,806)		(9,065,332)
Tax effect from change in tax rate (*)		(9,845,202)		148,137		(1,450,689)
Tax effect of over-provided tax in previous period		627,769		(882,687)		(2,869,081)
Price level restatement for tax purposes (investments and equity)		38,734,202		(20,739,780)		28,653,971
Total adjustments to tax expense using statutory rate		(150,800,592)		(194,161,230)		(100,068,753)

Income tax		(411,891,234)		(460,836,692)		(346,006,968)

(*) On July 29, 2010, Law No. 20,455 was passed in Chile, “Modifying different laws to obtain funds to finance the reconstruction of the country.” This law, which was published in the Diario Oficial (Official Gazette) on July 31, 2010, included a temporary First Category tax increase for the 2011 and 2012 business years (to 20% and 18.5%, respectively), with a return to the 17% tax rate for 2013.

Then, on September 27, 2012, Law No. 20,630, which modifies Chilean tax law to finance education reform, was published in the Diario Oficial (Official Gazette). Among other changes, this law increased the First Category tax rate from 18.5% to 20% starting in the 2012 business year

F-96

33.

SEGMENT INFORMATION

33.1

Segmentation criteria

The Group’s activities are organized primarily around its core businesses: electric energy generation, transmission, and distribution. On that basis, the Group has established two major business lines.

In addition, segment information has been organized by the geographical areas in which the Group operates:

• Chile

• Argentina

• Brazil

• Peru

• Colombia

Given that the Group’s corporate organization basically matches its business organization and, therefore, the segments organization, the following segment information is based on the financial information of the companies forming each segment.

The following tables present the segment information for the 2012, 2011, and 2010 fiscal years.

F-97

33.2

Generation, distribution, and others


Line of Business	Generation				Distribution				Eliminations and Others				Total
ASSETS	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$
CURRENT ASSETS		1,013,418,718		1,212,585,323		972,698,943		1,007,409,597		368,400,772		305,970,088		2,354,518,433		2,525,965,008
Cash and cash equivalents		351,175,599		552,738,084		227,349,107		298,945,821		278,855,312		368,237,363		857,380,018		1,219,921,268
Other current financial assets		58,019,211		914,209		47,888,142		25,011		88,593,445		-		194,500,798		939,220
Other current non-financial assets		32,543,209		31,292,979		71,060,646		38,792,524		2,315,912		2,380,809		105,919,767		72,466,312
Trade and other current receivables		264,449,963		355,609,508		590,560,176		610,324,178		14,194,427		11,668,702		869,204,566		977,602,388
Accounts receivable from related companies		80,522,375		130,673,380		3,840,971		7,215,786		(51,334,435)		(102,606,574)		33,028,911		35,282,592
Inventories		65,683,582		55,906,768		13,480,478		16,354,914		4,315,433		5,663,862		83,479,493		77,925,544
Current tax assets		161,024,779		85,450,395		18,519,423		35,751,363		31,460,678		20,625,926		211,004,880		141,827,684

Non-current assets classified as held for sale and discontinued operations		-		-		-		-		-		-		-		-

NON-CURRENT ASSETS		6,143,596,315		6,154,273,562		4,638,627,634		4,778,151,088		181,091,258		275,481,094		10,963,315,207		11,207,905,744
Other non-current financial assets		33,402,903		13,598,337		378,529,672		2,826,723		27,183,342		20,930,001		439,115,917		37,355,061
Other non-current non-financial assets		26,383,971		28,731,435		61,314,310		80,741,831		123,850		27,842		87,822,131		109,501,108
Non-current receivables		150,483,725		175,400,312		51,808,642		267,256,936		685,326		671,202		202,977,693		443,328,450
Non-current accounts receivable from related companies		-		(1,863,216)		99,044		117,946		(99,044)		1,745,270		-		-
Investments accounted for using the equity method		595,392,564		591,668,155		510,762,349		503,610,981		(1,093,978,229)		(1,082,085,874)		12,176,684		13,193,262
Intangible assets other than goodwill		49,214,509		35,332,818		1,139,014,116		1,417,846,070		14,906,949		14,219,326		1,203,135,574		1,467,398,214
Goodwill		101,760,013		106,399,041		110,434,834		129,382,377		1,187,681,742		1,240,622,708		1,399,876,589		1,476,404,126
Property, plant, and equipment, net		5,034,784,953		5,068,294,024		2,217,433,639		2,180,696,470		(8,598,383)		(6,259,488)		7,243,620,209		7,242,731,006
Investment property		-		-		-		-		46,922,970		38,055,889		46,922,970		38,055,889
Deferred tax assets		152,173,677		136,712,656		169,231,028		195,671,754		6,262,735		47,554,218		327,667,440		379,938,628

TOTAL ASSETS		7,157,015,033		7,366,858,885		5,611,326,577		5,785,560,685		549,492,030		581,451,182		13,317,833,640		13,733,870,752

F-98


	Generation				Distribution				Eliminations and Others				Total
LIABILITIES AND EQUITY	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$
CURRENT LIABILITIES		1,229,989,919		1,150,249,283		1,351,754,251		1,394,053,750		(200,631,935)		(83,769,398)		2,381,112,235		2,460,533,635
Other current financial liabilities		416,888,973		365,375,002		238,078,498		292,160,116		15,214,737		14,547,220		670,182,208		672,082,338
Trade and other current payables		370,500,603		380,701,746		779,661,721		774,128,579		63,097,411		80,234,134		1,213,259,735		1,235,064,459
Accounts payable to related companies		301,401,943		234,167,088		139,176,662		126,083,948		(293,751,194)		(203,073,398)		146,827,411		157,177,638
Other short-term provisions		39,720,320		36,030,224		44,316,361		43,227,192		7,094,014		20,445,238		91,130,695		99,702,654
Current tax liabilities		91,149,629		122,601,990		76,419,202		110,935,913		5,567,879		2,315,339		173,136,710		235,853,242
Current provisions for employee benefits		-		-		-		-		-		-		-		-
Other current non-financial liabilities		10,328,451		11,373,233		74,101,807		47,518,002		2,145,218		1,762,069		86,575,476		60,653,304

Liabilities associated with non-current assets classified as held for sale and discontinued operations		-		-		-		-		-		-		-		-

NON-CURRENT LIABILITIES		2,040,272,104		2,231,327,095		1,436,704,775		1,572,059,394		495,975,948		573,796,771		3,972,952,827		4,377,183,260
Other non-current financial liabilities		1,545,210,455		1,755,575,529		824,212,315		952,894,143		558,697,099		562,885,621		2,928,119,869		3,271,355,293
Other non-current payables		175,898		243,234		14,081,540		14,060,817		-		556		14,257,438		14,304,607
Accounts payable to related companies		7,114,225		81,953		-		-		(7,114,225)		(81,953)		-		-
Other long-term provisions		26,347,451		20,833,139		144,386,384		181,636,893		6,345,154		103,609		177,078,989		202,573,641
Deferred tax liabilities		368,906,755		341,568,310		196,503,392		162,528,439		(46,384,101)		4,341,506		519,026,046		508,438,255
Non-current provisions for employee benefits		39,720,916		36,504,909		218,519,259		234,826,662		6,827,714		6,194,442		265,067,889		277,526,013
Other non-current non-financial liabilities		52,796,404		76,520,021		39,001,885		26,112,440		(22,395,693)		352,990		69,402,596		102,985,451

EQUITY		3,886,753,010		3,985,282,507		2,822,867,551		2,819,447,541		254,148,017		91,423,809		6,963,768,578		6,896,153,857
Equity attributable to shareholders of Enersis		3,886,753,010		3,985,282,507		2,822,867,551		2,819,447,541		254,148,017		91,423,809		3,893,798,571		3,895,728,606
Issued capital		1,488,171,918		1,752,890,037		829,508,479		1,010,886,630		507,202,438		61,106,168		2,824,882,835		2,824,882,835
Retained earnings		1,890,441,860		1,838,419,172		1,283,404,467		957,047,345		(752,567,486)		(562,497,637)		2,421,278,841		2,232,968,880
Share premium		206,008,557		-		4,180,489		-		(51,429,398)		158,759,648		158,759,648		158,759,648
Other reserves		302,130,675		393,973,298		705,774,116		851,513,566		550,942,463		434,055,630		(1,511,122,753)		(1,320,882,757)

Non-controlling interests		-		-		-		-		-		-		3,069,970,007		3,000,425,251

TOTAL LIABILITIES AND EQUITY		7,157,015,033		7,366,858,885		5,611,326,577		5,785,560,685		549,492,030		581,451,182		13,317,833,640		13,733,870,752

F-99


	Generation									Distribution								Eliminations and Others							Total
STATEMENT OF COMPREHENSIVE INCOME	12-31-2012 ThCh$			12-31-2011 ThCh$			12-31-2010 ThCh$			12-31-2012 ThCh$		12-31-2011 ThCh$			12-31-2010 ThCh$			12-31-2012 ThCh$			12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$
REVENUE		2,727,263,010			2,700,026,218			2,780,604,080			4,460,244,983		4,447,427,469			4,392,625,917			(609,840,679	)		(612,573,343)		(609,648,884)		6,577,667,314		6,534,880,344		6,563,581,113
Sales		2,659,632,536			2,681,583,403			2,735,336,937			4,217,769,377		4,187,214,704			4,053,333,247			(617,092,684	)		(614,546,018)		(609,440,360)		6,260,309,229		6,254,252,089		6,179,229,824
Energy sales		2,519,046,562			2,587,301,858			2,599,487,673			3,854,175,793		3,830,011,900			3,754,753,999			(580,058,502	)		(612,017,484)		(700,516,755)		5,793,163,853		5,805,296,274		5,653,724,917
Other sales		9,891,453			10,642,489			15,262,308			11,735,865		8,391,707			9,220,770			8,438,089			12,711,978		26,087,696		30,065,407		31,746,174		50,570,774
Other services rendered		130,694,521			83,639,056			120,586,956			351,857,719		348,811,097			289,358,478			(45,472,271	)		(15,240,512)		64,988,699		437,079,969		417,209,641		474,934,133

Other operating revenue		67,630,474			18,442,815			45,267,143			242,475,606		260,212,765			339,292,670			7,252,005			1,972,675		(208,524)		317,358,085		280,628,255		384,351,289

SUPPLIES AND SERVICES		(1,459,307,267	)		(1,272,985,092	)		(1,300,760,188	)		(2,883,450,602)		(2,904,965,972	)		(2,861,855,754	)		625,632,382			639,516,335		640,969,688		(3,717,125,487)		(3,538,434,729)		(3,521,646,254)
Energy purchases		(359,323,987	)		(272,699,080	)		(264,194,654	)		(2,076,163,493)		(2,099,527,411	)		(1,988,241,950	)		580,157,168			609,408,193		697,721,968		(1,855,330,312)		(1,762,818,298)		(1,554,714,636)
Fuel consumption		(782,255,866	)		(742,631,157	)		(672,030,596	)		-		-			-			(7,870	)		(8,206)		(7,507)		(782,263,736)		(742,639,363)		(672,038,103)
Transport expenses		(245,278,912	)		(210,422,135	)		(233,134,592	)		(272,879,404)		(228,281,706	)		(216,929,666	)		48,309,487			44,712,720		44,081,166		(469,848,829)		(393,991,121)		(405,983,092)
Other miscellaneous supplies and services		(72,448,502	)		(47,232,720	)		(131,400,346	)		(534,407,705)		(577,156,855	)		(656,684,138	)		(2,826,403	)		(14,596,372)		(100,825,939)		(609,682,610)		(638,985,947)		(888,910,423)

CONTRIBUTION MARGIN		1,267,955,743			1,427,041,126			1,479,843,892			1,576,794,381		1,542,461,497			1,530,770,163			15,791,703			26,942,992		31,320,804		2,860,541,827		2,996,445,615		3,041,934,859

Infrastructure work		13,476,347			6,404,803			688,024			35,377,340		39,331,002			34,742,737			-			4,437,307		9,438,604		48,853,687		50,173,112		44,869,365
Employee expenses		(118,485,904	)		(84,624,505	)		(76,018,545	)		(265,751,973)		(252,417,780	)		(215,810,871	)		(32,107,263	)		(41,509,841)		(82,848,597)		(416,345,140)		(378,552,126)		(374,678,013)
Other fixed operating expenses		(126,226,860	)		(148,540,710	)		(109,570,881	)		(387,022,650)		(389,777,503	)		(366,421,018	)		3,123,600			(2,380,184)		25,557,129		(510,125,910)		(540,698,397)		(450,434,770)

GROSS OPERATING RESULT		1,036,719,326			1,200,280,714			1,294,942,490			959,397,098		939,597,216			983,281,011			(13,191,960	)		(12,509,726)		(16,532,060)		1,982,924,464		2,127,368,204		2,261,691,441

Depreciation and amortization expense		(235,633,898	)		(205,906,910	)		(244,848,894	)		(260,150,321)		(347,074,905	)		(291,545,800	)		9,824,303			(8,075,680)		(20,996,010)		(485,959,916)		(561,057,495)		(557,390,704)

OPERATING INCOME		801,085,428			994,373,804			1,050,093,596			699,246,777		592,522,311			691,735,211			(3,367,657	)		(20,585,406)		(37,528,070)		1,496,964,548		1,566,310,709		1,704,300,737

FINANCIAL RESULT		(144,688,843	)		(96,533,304	)		(139,201,816	)		(46,679,711)		(114,211,524	)		(94,631,362	)		(24,820,154	)		(25,840,179)		(36,771,357)		(216,188,708)		(236,585,007)		(270,604,535)

Financial income		38,804,106			88,970,416			27,878,995			215,787,202		127,716,519			132,691,391			10,117,927			16,925,934		10,666,562		264,709,235		233,612,869		171,236,948
Financial expenses		(170,216,457	)		(187,258,748	)		(178,031,427	)		(265,607,111)		(242,555,022	)		(227,390,652	)		(17,623,869	)		(35,597,593)		(32,936,172)		(453,447,437)		(465,411,363)		(438,358,251)
Gain (loss) from indexed assets and liabilities		(710,227	)		(5,369,555	)		(2,885,747	)		1,204,984		42,067			153,805			(13,176,385	)		(19,764,715)		(12,323,764)		(12,681,628)		(25,092,203)		(15,055,706)
Foreign currency exchange differences		(12,566,265	)		7,124,583			13,836,363			1,935,214		584,912			(85,906	)		(4,137,827	)		12,596,195		(2,177,983)		(14,768,878)		20,305,690		11,572,474
Positive		20,648,464			36,535,322			59,331,363			3,704,945		4,951,758			7,255,856			24,407,877			39,385,744		24,744,149		48,761,286		80,872,824		91,331,368
Negative		(33,214,729	)		(29,410,739	)		(45,495,000	)		(1,769,731)		(4,366,846	)		(7,341,762	)		(28,545,704	)		(26,789,549)		(26,922,132)		(63,530,164)		(60,567,134)		(79,758,894)

Share of the profit (loss) from associates accounted for using the equity method		9,845,902			8,215,763			811,855			310		468			911			(310	)		249,673		202,973		9,845,902		8,465,904		1,015,739
Gain (loss) from other investments		657,026			1,038,160			234,251			80,290		70			-			-			-		38,435		737,316		1,038,230		272,686
Gain (loss) on the sale of property, plant, and equipment		735,259			975,577			1,631,416			987,306		(313,790	)		1,365,276			12,371,593			(6,514,311)		8,714,057		14,094,158		(5,852,524)		11,710,749

NET INCOME BEFORE TAX		667,634,772			908,070,000			913,569,302			653,634,972		477,997,535			598,470,036			(15,816,528	)		(52,690,223)		(65,343,962)		1,305,453,216		1,333,377,312		1,446,695,376

Income tax		(211,488,549	)		(255,341,927	)		(197,493,560	)		(213,455,380)		(200,528,618	)		(141,600,737	)		13,052,695			(4,966,147)		(6,912,671)		(411,891,234)		(460,836,692)		(346,006,968)

NET INCOME AFTER TAX FROM CONTINUING OPERATIONS		456,146,223			652,728,073			716,075,742			440,179,592		277,468,917			456,869,299			(2,763,833	)		(57,656,370)		(72,256,633)		893,561,982		872,540,620		1,100,688,408
Net income from discontinued operations		-			-			-			-		-			-			-			-		-		-		-		-
NET INCOME		456,146,223			652,728,073			716,075,742			440,179,592		277,468,917			456,869,299			(2,763,833	)		(57,656,370)		(72,256,633)		893,561,982		872,540,620		1,100,688,408

NET INCOME ATTRIBUTABLE TO		456,146,223			652,728,073			716,075,742			440,179,592		277,468,917			456,869,299			(2,763,833	)		(57,656,370)		(72,256,633)		893,561,982		872,540,620		1,100,688,408
Shareholders of Enersis		-			-			-			-		-			-			-			-		-		377,350,521		375,471,254		486,226,814
Non-controlling interests		-			-			-			-		-			-			-			-		-		516,211,461		497,069,366		614,461,594

F-100

33.3

Countries


Country	Chile				Argentina				Brazil				Colombia				Peru				Eliminations				Total
ASSETS	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$
CURRENT ASSETS		831,919,458		1,117,076,586		140,651,609		198,804,567		742,319,957		680,639,176		528,267,777		439,170,846		154,280,243		138,640,931		(42,920,611)		(48,367,098)		2,354,518,433		2,525,965,008
Cash and cash equivalents		257,595,771		588,127,702		20,619,433		43,522,761		195,713,589		277,962,207		320,342,460		268,253,856		63,108,765		42,054,742		-		-		857,380,018		1,219,921,268
Other current financial assets		3,865		47,504		248,729		143,638		143,275,069		-		50,921,259		699,517		51,876		48,561		-		-		194,500,798		939,220
Other current non-financial assets		11,275,320		8,430,910		1,207,678		2,444,742		72,727,847		43,310,737		13,799,808		13,185,071		6,909,114		5,094,852		-		-		105,919,767		72,466,312
Trade and other current receivables		315,294,444		338,292,487		70,793,684		108,345,327		291,578,428		318,551,280		123,660,742		137,785,949		66,634,074		73,975,674		1,243,194		651,671		869,204,566		977,602,388
Accounts receivable from related companies		31,805,819		49,976,938		33,308,107		34,084,870		11,804,423		-		239,701		30,857		34,666		208,696		(44,163,805)		(49,018,769)		33,028,911		35,282,592
Inventories		42,118,709		37,057,881		6,392,567		4,921,951		659,321		1,266,810		17,026,589		17,676,019		17,282,307		17,002,883		-		-		83,479,493		77,925,544
Current tax assets		173,825,530		95,143,164		8,081,411		5,341,278		26,561,280		39,548,142		2,277,218		1,539,577		259,441		255,523		-		-		211,004,880		141,827,684

Non-current assets classified as held for sale and discontinued operations		-		-		-		-		-		-		-		-		-		-		-		-		-		-

NON-CURRENT ASSETS		7,726,466,170		7,893,250,054		586,838,081		593,346,110		3,338,211,800		3,805,276,862		2,541,027,789		2,353,927,049		1,243,142,279		1,246,563,957		(4,472,370,912)		(4,684,458,288)		10,963,315,207		11,207,905,744
Other non-current financial assets		58,719,191		32,942,181		194,354		161,140		375,250,800		27,818		1,243,527		1,214,684		3,708,045		3,009,238		-		-		439,115,917		37,355,061
Other non-current non-financial assets		414,689		599,529		1,833,586		1,984,737		83,997,877		106,916,842		1,710,515		-		-		-		(134,536)		-		87,822,131		109,501,108
Non-current receivables		7,548,389		4,531,190		146,227,334		151,690,773		35,809,875		273,379,275		13,392,095		13,727,212		-		-		-		-		202,977,693		443,328,450
Non-current accounts receivable from related companies		5,712,830		6,179,892		-		-		32,432,608		44,861,006		-		-		-		-		(38,145,438)		(51,040,898)		-		-
Investments accounted for using the equity method		4,494,808,784		4,681,940,902		58,167,386		4,727,255		1,042,410,728		1,217,587,204		1,716		76		51,856,847		49,887,780		(5,635,068,777)		(5,940,949,955)		12,176,684		13,193,262
Intangible assets other than goodwill		38,128,352		40,438,658		3,460,809		3,649,971		1,104,062,844		1,375,676,408		44,835,547		44,330,454		12,648,022		3,302,723		-		-		1,203,135,574		1,467,398,214
Goodwill		2,311,535		2,312,632		1,902,217		2,357,592		100,004,647		119,058,905		13,384,051		13,209,651		8,703,399		10,361,690		1,273,570,740		1,329,103,656		1,399,876,589		1,476,404,126
Property, plant, and equipment, net		2,975,632,116		2,998,303,344		369,087,363		424,077,441		388,190,909		479,342,553		2,366,990,760		2,184,994,520		1,164,386,651		1,178,479,794		(20,667,590)		(22,466,646)		7,243,620,209		7,242,731,006
Investment property		46,922,970		38,055,889		-		-		-		-		-		-		-		-		-		-		46,922,970		38,055,889
Deferred tax assets		96,267,314		87,945,837		5,965,032		4,697,201		176,051,512		188,426,851		99,469,578		96,450,452		1,839,315		1,522,732		(51,925,311)		895,555		327,667,440		379,938,628

TOTAL ASSETS		8,558,385,628		9,010,326,640		727,489,690		792,150,677		4,080,531,757		4,485,916,038		3,069,295,566		2,793,097,895		1,397,422,522		1,385,204,888		(4,515,291,523)		(4,732,825,386)		13,317,833,640		13,733,870,752

F-101


Country	Chile				Argentina				Brazil				Colombia				Peru				Eliminations				Total
LIABILITIES AND EQUITY	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$
CURRENT LIABILITIES		731,293,242		661,869,058		592,608,749		494,783,567		444,716,883		650,237,150		457,200,629		483,448,241		192,966,046		170,828,751		(37,673,314)		(633,132)		2,381,112,235	2,460,533,635
Other current financial liabilities		239,780,483		88,087,416		156,782,528		105,336,295		111,001,976		288,730,920		101,481,299		124,904,402		61,135,922		65,023,305		-		-		670,182,208	672,082,338
Trade and other current payables		320,960,507		405,601,668		335,942,011		283,219,858		246,490,233		234,837,848		214,380,281		223,557,756		85,340,558		68,645,529		10,146,145		19,201,800		1,213,259,735	1,235,064,459
Accounts payable to related companies		92,373,636		48,929,239		32,357,914		45,686,586		31,861,534		34,092,017		36,962,589		51,713,966		1,091,197		1,068,536		(47,819,459)		(24,312,706)		146,827,411	157,177,638
Other short-term provisions		41,152,803		54,333,202		30,095,780		25,324,807		1,559,596		6,801,936		9,808,093		10,860		8,514,423		8,754,075		-		4,477,774		91,130,695	99,702,654
Current tax liabilities		32,415,239		58,625,870		10,649,219		12,379,051		35,085,220		67,476,356		85,599,986		76,893,506		9,387,046		20,478,459		-		-		173,136,710	235,853,242
Current provisions for employee benefits		-		-		-		-		-		-		-		-		-		-		-		-		-	-
Other current non-financial liabilities		4,610,574		6,291,663		26,781,297		22,836,970		18,718,324		18,298,073		8,968,381		6,367,751		27,496,900		6,858,847		-		-		86,575,476	60,653,304

Liabilities associated with non-current assets classified as held for sale and discontinued operations		-		-		-		-		-		-		-		-		-		-		-		-		-	-

NON-CURRENT LIABILITIES		1,537,883,407		1,819,290,887		113,903,928		206,938,488		860,959,079		929,216,917		1,087,503,179		928,038,093		484,376,415		527,947,698		(111,673,181)		(34,248,823)		3,972,952,827	4,377,183,260
Other non-current financial liabilities		1,208,350,892		1,538,473,627		23,630,252		113,544,053		465,777,075		515,352,311		945,721,006		782,142,214		284,640,644		321,843,088		-		-		2,928,119,869	3,271,355,293
Other non-current payables		-		-		175,794		1,146,930		14,081,644		13,157,677		-		-		-		-		-		-		14,257,438	14,304,607
Accounts payable to related companies		-		-		37,013,568		34,248,823		-		-		-		-		-		-		(37,013,568)		(34,248,823)		-	-
Other long-term provisions		25,283,772		17,935,877		7,830,745		9,239,778		137,536,697		168,801,883		3,493,633		4,762,542		2,934,142		1,833,561		-		-		177,078,989	202,573,641
Deferred tax liabilities		221,385,312		204,262,599		10,812,791		13,419,881		113,029,606		67,691,941		30,956,734		19,717,371		193,015,503		203,346,463		(50,173,900)		-		519,026,046	508,438,255
Non-current provisions for employee benefits		40,221,634		35,817,248		7,014,199		7,627,051		127,516,473		149,353,832		88,078,806		84,727,882		2,236,777		-		-		-		265,067,889	277,526,013
Other non-current non-financial liabilities		42,641,797		22,801,536		27,426,579		27,711,972		3,017,584		14,859,273		19,253,000		36,688,084		1,549,349		924,586		(24,485,713)		-		69,402,596	102,985,451

EQUITY		6,289,208,979		6,529,166,695		20,977,013		90,428,622		2,774,855,795		2,906,461,971		1,524,591,758		1,381,611,561		720,080,061		686,428,439		(4,365,945,028)		(4,697,943,431)		6,963,768,578	6,896,153,857
Equity attributable to shareholders of Enersis		6,289,208,979		6,529,166,695		20,977,013		90,428,622		2,774,855,795		2,906,461,971		1,524,591,758		1,381,611,561		720,080,061		686,428,439		(4,365,945,028)		(4,697,943,431)		3,893,798,571	6,896,153,857
Issued capital		5,183,178,569		5,517,944,809		192,387,594		230,798,614		946,283,652		1,768,841,536		168,180,369		150,811,424		223,717,228		197,139,383		(3,888,864,577)		(5,040,652,931)		2,824,882,835	2,824,882,835
Retained earnings		2,699,189,299		2,728,371,595		(177,577,796)		(99,901,666)		640,153,933		459,494,106		632,034,321		125,770,175		135,999,421		72,384,455		(1,508,520,337)		(1,053,149,785)		2,421,278,841	2,232,968,880
Share premium		365,334,507		158,759,648		-		-		630,233,239		-		3,614,187		-		-		-		(840,422,285)		-		158,759,648	158,759,648
Other reserves		(1,958,493,396)		(1,875,909,357)		6,167,215		(40,468,326)		558,184,971		678,126,329		720,762,881		1,105,029,962		360,363,412		416,904,601		1,871,862,171		1,395,859,285		(1,511,122,753)	1,679,542,494

Non-controlling interests		-		-		-		-		-		-		-		-		-		-		-		-		3,069,970,007	3,000,425,251

Total Liabilities and Equity		8,558,385,628		9,010,326,640		727,489,690		792,150,677		4,080,531,757		4,485,916,038		3,069,295,566		2,793,097,895		1,397,422,522		1,385,204,888		(4,515,291,523)		(4,732,825,386)		13,317,833,640	13,733,870,752

F-102


Country	Chile						Argentina						Brazil						Colombia						Peru						Eliminations						Total
STATEMENT OF COMPREHENSIVE INCOME	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$
REVENUE		1,951,674,107		2,124,479,297		2,085,557,501		668,889,354		675,647,122		658,417,051		2,128,031,611		2,165,287,761		2,230,116,193		1,262,681,733		1,113,791,686		1,163,978,952		568,105,957		458,047,567		429,229,748		(1,715,448)		(2,373,089)		(3,718,332)		6,577,667,314		6,534,880,344		6,563,581,113
Sales		1,871,175,380		2,097,527,758		2,041,203,346		653,895,892		667,299,420		644,085,670		1,963,812,830		1,970,909,825		1,953,154,510		1,226,947,305		1,080,920,739		1,135,970,285		546,249,646		439,967,436		408,534,345		(1,771,824)		(2,373,089)		(3,718,332)		6,260,309,229		6,254,252,089		6,179,229,824
Energy sales		1,710,323,039		1,961,366,637		1,868,868,808		634,079,879		641,615,807		614,505,180		1,785,616,550		1,787,773,720		1,778,434,279		1,134,215,302		991,306,129		1,019,682,987		528,929,083		423,233,981		372,233,663		-		-		-		5,793,163,853		5,805,296,274		5,653,724,917
Other sales		21,064,337		21,888,297		37,515,316		412,885		-		-		5,800,382		6,072,128		3,332,080		2,749,302		3,289,633		6,557,919		38,501		565,295		4,375,367		-		(69,179)		(1,209,908)		30,065,407		31,746,174		50,570,774
Other services rendered		139,788,004		114,272,824		134,819,222		19,403,128		25,683,613		29,580,490		172,395,898		177,063,977		171,388,151		89,982,701		86,324,977		109,729,379		17,282,062		16,168,160		31,925,315		(1,771,824)		(2,303,910)		(2,508,424)		437,079,969		417,209,641		474,934,133
Other operating revenue		80,498,727		26,951,539		44,354,155		14,993,462		8,347,702		14,331,381		164,218,781		194,377,936		276,961,683		35,734,428		32,870,947		28,008,667		21,856,311		18,080,131		20,695,403		56,376		-		-		317,358,085		280,628,255		384,351,289

SUPPLIES AND SERVICES		(1,289,222,399)		(1,280,894,315)		(1,157,432,602)		(456,896,885)		(457,898,841)		(413,059,847)		(1,261,178,856)		(1,228,453,536)		(1,308,455,877)		(445,729,779)		(385,326,627)		(463,847,068)		(264,153,581)		(185,931,510)		(180,533,345)		56,013		70,100		1,682,485		(3,717,125,487)		(3,538,434,729)		(3,521,646,254)
Energy purchases		(678,966,060)		(747,064,363)		(542,253,232)		(188,141,869)		(153,569,548)		(148,902,836)		(602,540,950)		(587,111,958)		(543,260,558)		(228,612,851)		(186,337,063)		(246,229,847)		(158,288,518)		(88,735,366)		(74,068,163)		1,219,936		-		-		(1,855,330,312)		(1,762,818,298)		(1,554,714,636)
Fuel consumption		(403,832,711)		(350,733,784)		(318,644,651)		(255,215,278)		(283,048,981)		(242,853,893)		(31,481,376)		(35,498,349)		(37,260,897)		(36,215,949)		(23,946,682)		(27,780,401)		(55,518,422)		(49,411,567)		(45,498,261)		-		-		-		(782,263,736)		(742,639,363)		(672,038,103)
Transport expenses		(183,856,206)		(146,853,453)		(183,181,403)		(4,645,155)		(9,143,907)		(4,875,869)		(142,758,291)		(107,475,644)		(93,660,230)		(117,783,015)		(114,302,814)		(111,637,522)		(19,580,741)		(16,215,303)		(12,628,068)		(1,225,421)		-		-		(469,848,829)		(393,991,121)		(405,983,092)
Other miscellaneous supplies and services		(22,567,422)		(36,242,715)		(113,353,316)		(8,894,583)		(12,136,405)		(16,427,249)		(484,398,239)		(498,367,585)		(634,274,192)		(63,117,964)		(60,740,068)		(78,199,298)		(30,765,900)		(31,569,274)		(48,338,853)		61,498		70,100		1,682,485		(609,682,610)		(638,985,947)		(888,910,423)

CONTRIBUTION MARGIN		662,451,708		843,584,982		928,124,899		211,992,469		217,748,281		245,357,204		866,852,755		936,834,225		921,660,316		816,951,954		728,465,059		700,131,884		303,952,376		272,116,057		248,696,403		(1,659,435)		(2,302,989)		(2,035,847)		2,860,541,827		2,996,445,615		3,041,934,859

Infrastructure Work		11,267,277		11,168,239		11,962,653		12,470,077		12,146,533		8,296,765		15,741,610		18,130,297		18,128,254		6,683,819		6,497,714		4,423,015		2,690,904		2,230,329		2,058,678		-		-		-		48,853,687		50,173,112		44,869,365
Employee expenses		(109,479,374)		(105,910,635)		(113,164,815)		(119,207,683)		(106,287,626)		(79,533,998)		(106,756,270)		(110,708,252)		(109,354,257)		(49,828,233)		(48,007,413)		(51,541,615)		(31,073,580)		(7,638,200)		(21,083,328)		-		-		-		(416,345,140)		(378,552,126)		(374,678,013)
Other fixed operating expenses		(117,970,286)		(113,660,232)		(100,976,501)		(114,875,019)		(88,827,726)		(89,055,759)		(154,523,039)		(161,072,702)		(148,686,023)		(83,570,075)		(146,263,633)		(78,880,441)		(40,846,681)		(33,100,304)		(33,890,176)		1,659,190		2,226,200		1,054,130		(510,125,910)		(540,698,397)		(450,434,770)

GROSS OPERATING RESULT		446,269,325		635,182,354		725,946,236		(9,620,156)		34,779,462		85,064,212		621,315,056		683,183,568		681,748,290		690,237,465		540,691,727		574,132,843		234,723,019		233,607,882		195,781,577		(245)		(76,789)		(981,717)		1,982,924,464		2,127,368,204		2,261,691,441

Amortization and impairment losses		(142,779,068)		(123,699,667)		(119,048,628)		(38,927,101)		(138,094,097)		(34,724,329)		(143,641,558)		(131,553,418)		(229,368,430)		(107,406,499)		(101,908,200)		(102,190,376)		(63,764,857)		(59,219,178)		(60,339,333)		10,559,167		(6,582,935)		(11,719,608)		(485,959,916)		(561,057,495)		(557,390,704)

OPERATING INCOME		303,490,257		511,482,687		606,897,608		(48,547,257)		(103,314,635)		50,339,883		477,673,498		551,630,150		452,379,860		582,830,966		438,783,527		471,942,467		170,958,162		174,388,704		135,442,244		10,558,922		(6,659,724)		(12,701,325)		1,496,964,548		1,566,310,709		1,704,300,737

FINANCIAL RESULT		(90,680,060)		(78,797,719)		(106,356,565)		(64,962,488)		(31,563,414)		(15,788,697)		30,905,320		(32,405,059)		(64,838,758)		(65,771,378)		(76,360,671)		(62,523,560)		(28,142,657)		(22,714,456)		(25,742,132)		2,462,555		5,256,312		4,645,177		(216,188,708)		(236,585,007)		(270,604,535)
Financial income		25,219,811		34,484,561		15,604,598		8,339,316		13,314,838		10,926,110		214,704,387		173,831,176		132,197,987		13,449,518		11,407,941		11,883,669		5,284,506		2,723,717		2,116,913		(2,288,303)		(2,149,364)		(1,492,329)		264,709,235		233,612,869		171,236,948
Financial expenses		(97,768,649)		(93,072,101)		(109,360,408)		(57,873,835)		(36,394,214)		(34,924,333)		(187,444,374)		(225,571,907)		(193,320,965)		(79,035,438)		(87,553,973)		(74,211,667)		(33,613,441)		(24,968,532)		(28,154,018)		2,288,300		2,149,364		1,613,140		(453,447,437)		(465,411,363)		(438,358,251)
Gain (loss) from indexed assets and liabilities		(12,681,628)		(25,092,203)		(15,055,706)		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		(12,681,628)		(25,092,203)		(15,055,706)
Foreign currency exchange differences		(5,449,594)		4,882,024		2,454,951		(15,427,969)		(8,484,038)		8,209,526		3,645,307		19,335,672		(3,715,780)		(185,458)		(214,639)		(195,562)		186,278		(469,641)		294,973		2,462,558		5,256,312		4,524,366		(14,768,878)		20,305,690		11,572,474
Positive		33,256,197		53,545,105		38,536,192		9,384,231		6,006,240		20,715,091		9,445,578		29,865,459		30,931,909		743,054		738,510		963,520		934,728		702,589		1,553,835		(5,002,502)		(9,985,079)		(1,369,179)		48,761,286		80,872,824		91,331,368
Negative		(38,705,791)		(48,663,081)		(36,081,241)		(24,812,200)		(14,490,278)		(12,505,565)		(5,800,271)		(10,529,787)		(34,647,689)		(928,512)		(953,149)		(1,159,082)		(748,450)		(1,172,230)		(1,258,862)		7,465,060		15,241,391		5,893,545		(63,530,164)		(60,567,134)		(79,758,894)

Share of the profit (loss) from associates accounted for using the equity method		9,845,902		8,215,729		811,657		-		250,141		203,884		-		-		-		-		-		-		11,120,212		-		-		-		34		198		9,845,902		8,465,904		1,015,739
Negative consolidation difference		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Gain (loss) from other investments		158,287		1,053,408		1,626,786		579,029		498,877		1,596,643		-		-		29,251		-		70		-		-		-		-		-		(514,125)		(2,979,994)		737,316		1,038,230		272,686
Gain (loss) on the sale of property, plant, and equipment		12,182,160		(6,039,997)		8,825,168		2,032		-		-		1,983,259		-		(34,754)		(537,749)		(230,878)		2,515,018		464,456		418,351		405,317		-		-		-		14,094,158		(5,852,524)		11,710,749
Other expenses distinct from operating expenses		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-

NET INCOME BEFORE TAX		234,996,546		435,914,108		511,804,654		(112,928,684)		(134,129,031)		36,351,713		510,562,077		519,225,091		387,535,599		516,521,839		362,192,048		411,933,925		154,400,173		152,092,599		110,105,429		13,021,477		(1,917,503)		(11,035,944)		1,305,453,216		1,333,377,312		1,446,695,376

Income tax		(56,244,909)		(110,530,699)		(91,503,756)		(2,938,736)		(34,044,480)		(13,131,879)		(131,150,308)		(129,039,820)		(66,998,716)		(169,989,950)		(142,998,659)		(134,315,662)		(49,815,919)		(44,223,034)		(40,056,955)		(1,751,412)		-		-		(411,891,234)		(460,836,692)		(346,006,968)

NET INCOME AFTER TAX FROM CONTINUING OPERATIONS		178,751,637		325,383,409		420,300,898		(115,867,420)		(168,173,511)		23,219,834		379,411,769		390,185,271		320,536,883		346,531,889		219,193,389		277,618,263		104,584,254		107,869,565		70,048,474		11,270,065		(1,917,503)		(11,035,944)		893,561,982		872,540,620		1,100,688,408
Net income from discontinued operations		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-
NET INCOME		178,751,637		325,383,409		420,300,898		(115,867,420)		(168,173,511)		23,219,834		379,411,769		390,185,271		320,536,883		346,531,889		219,193,389		277,618,263		104,584,254		107,869,565		70,048,474		11,270,065		(1,917,503)		(11,035,944)		893,561,982		872,540,620		1,100,688,408

NET INCOME ATTRIBUTABLE TO		178,751,637		325,383,409		420,300,898		(115,867,420)		(168,173,511)		23,219,834		379,411,769		390,185,271		320,536,883		346,531,889		219,193,389		277,618,263		104,584,254		107,869,565		70,048,474		11,270,065		(1,917,503)		(11,035,944)		893,561,982		872,540,620		1,100,688,408
Shareholders of Enersis		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		377,350,521		375,471,254		486,226,814
Non-controlling interests		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		516,211,461		497,069,366		614,461,594

F-103

33.4

Generation and distribution by country

a) Generation


Line of Business	Generation
Country	Chile				Argentina				Brazil				Colombia				Peru				Eliminations				Total
ASSETS	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$
CURRENT ASSETS		437,423,354		581,738,393		65,350,914		113,950,708		188,095,512		229,070,896		285,719,119		239,044,005		80,363,358		75,650,050		(43,533,539)		(26,868,729)		1,013,418,718	1,212,585,323
Cash and cash equivalents		47,373,205		230,289,585		6,613,187		22,383,610		74,132,078		131,040,180		187,772,861		136,260,140		35,284,268		32,764,569		-		-		351,175,599	552,738,084
Other current financial assets		-		47,504		-		143,638		32,899,426		-		25,067,909		674,506		51,876		48,561		-		-		58,019,211	914,209
Other current non-financial assets		8,068,318		5,388,772		224,900		1,197,748		12,492,705		14,283,730		7,515,740		7,964,428		4,241,546		2,458,301		-		-		32,543,209	31,292,979
Trade and other current receivables		155,074,373		175,085,843		19,901,491		54,090,162		34,854,848		63,940,752		35,378,529		45,507,596		18,439,139		16,985,155		801,583		-		264,449,963	355,609,508
Accounts receivable from related companies		38,590,300		58,683,378		32,524,660		33,441,555		29,309,511		19,803,730		15,211,112		35,104,241		9,221,914		10,509,205		(44,335,122)		(26,868,729)		80,522,375	130,673,380
Inventories		36,350,362		29,481,511		3,158,460		1,783,282		25,149		2,504		13,257,329		11,993,970		12,892,282		12,645,501		-		-		65,683,582	55,906,768
Current tax assets		151,966,796		82,761,800		2,928,216		910,713		4,381,795		-		1,515,639		1,539,124		232,333		238,758		-		-		161,024,779	85,450,395

Non-current assets classified as held for sale and discontinued operations		-		-		-		-		-		-		-		-		-		-		-		-		-	-

NON-CURRENT ASSETS		4,021,480,859		4,058,185,785		282,190,205		319,979,207		484,097,928		600,244,367		1,563,308,503		1,393,219,292		786,613,843		812,558,136		(994,095,023)		(1,029,913,225)		6,143,596,315	6,154,273,562
Other non-current financial assets		31,534,104		12,014,822		108,154		161,140		1		-		1,236,511		1,205,585		524,133		216,790		-		-		33,402,903	13,598,337
Other non-current non-financial assets		75,277		342,343		1,252,853		1,099,011		24,553,260		27,290,081		635,776		-		-		-		(133,195)		-		26,383,971	28,731,435
Non-current receivables		-		160,518		144,560,890		150,312,091		2,908,137		21,685,968		3,014,698		3,241,735		-		-		-		-		150,483,725	175,400,312
Non-current accounts receivable from related companies		5,712,830		6,179,892		-		-		29,806,493		42,997,790		-		-		-		-		(35,519,323)		(51,040,898)		-	(1,863,216)
Investments accounted for using the equity method		1,576,108,743		1,594,961,765		2,743,725		3,428,479		9,072,881		10,801,536		-		-		51,856,848		49,887,780		(1,044,389,633)		(1,067,411,405)		595,392,564	591,668,155
Intangible assets other than goodwill		12,783,179		11,005,836		126,534		176,228		2,647,693		1,410,902		23,938,624		22,281,991		9,718,479		457,861		-		-		49,214,509	35,332,818
Goodwill		12,927		14,024		1,902,217		2,357,592		-		-		5,194,342		5,126,657		8,703,399		10,361,690		85,947,128		88,539,078		101,760,013	106,399,041
Property, plant, and equipment, net		2,357,275,977		2,400,516,617		125,530,800		157,747,465		368,075,606		456,994,530		1,469,930,901		1,302,924,129		713,971,669		750,111,283		-		-		5,034,784,953	5,068,294,024
Investment property		-		-		-		-		-		-		-		-		-		-		-		-		-	-
Deferred tax assets		37,977,822		32,989,968		5,965,032		4,697,201		47,033,857		39,063,560		59,357,651		58,439,195		1,839,315		1,522,732		-		-		152,173,677	136,712,656

TOTAL ASSETS		4,458,904,213		4,639,924,178		347,541,119		433,929,915		672,193,440		829,315,263		1,849,027,622		1,632,263,297		866,977,201		888,208,186		(1,037,628,562)		(1,056,781,954)		7,157,015,033	7,366,858,885

F-104


Line of Business	Generation
Country	Chile				Argentina				Brazil				Colombia				Peru				Eliminations				Total
LIABILITIES AND EQUITY	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$
CURRENT LIABILITIES		621,365,932		419,861,754		216,250,046		184,089,684		169,123,436		223,439,239		179,614,548		220,413,976		80,997,178		77,444,300		(37,361,221)		25,000,330		1,229,989,919	1,150,249,283
Other current financial liabilities		224,565,699		73,513,845		129,148,163		82,987,086		6,224,991		62,027,186		29,534,134		113,869,956		27,415,986		32,976,929		-		-		416,888,973	365,375,002
Trade and other current payables		161,623,736		210,953,110		45,273,595		47,852,899		37,543,805		47,171,805		71,999,845		50,897,328		41,946,210		23,834,560		12,113,412		(7,957)		370,500,603	380,701,745
Accounts payable to related companies		183,073,508		69,582,013		31,066,357		43,569,836		111,905,008		81,664,568		23,917,636		14,328,510		914,067		13,875		(49,474,633)		25,008,287		301,401,943	234,167,089
Other short-term provisions		24,876,065		29,277,728		1,564,413		3,901,399		-		-		9,808,093		10,860		3,471,749		2,840,237		-		-		39,720,320	36,030,224
Current tax liabilities		24,713,259		31,286,802		7,807,388		5,362,401		11,488,571		30,425,114		42,623,796		40,779,406		4,516,615		14,748,267		-		-		91,149,629	122,601,990
Current provisions for employee benefits		-		-		-		-		-		-		-		-		-		-		-		-		-	-
Other current non-financial liabilities		2,513,665		5,248,256		1,390,130		416,063		1,961,061		2,150,566		1,731,044		527,916		2,732,551		3,030,432		-		-		10,328,451	11,373,233

Liabilities associated with non-current assets classified as held for sale and discontinued operations		-		-		-		-		-		-		-		-		-		-		-		-		-	-

NON-CURRENT LIABILITIES		897,649,297		1,193,061,174		95,913,004		165,441,384		37,449,700		58,875,184		757,392,281		530,859,723		282,137,010		317,338,453		(30,269,188)		(34,248,823)		2,040,272,104	2,231,327,095
Other non-current financial liabilities		649,653,793		975,588,006		20,701,104		87,602,569		26,586,073		36,725,221		711,308,825		486,420,793		136,960,660		169,238,940		-		-		1,545,210,455	1,755,575,529
Other non-current payables		-		-		175,794		241,287		104		1,947		-		-		-		-		-		-		175,898	243,234
Accounts payable to related companies		-		81,953		37,013,568		34,248,823		-		-		-		-		-		-		(29,899,343)		(34,248,823)		7,114,225	81,953
Other long-term provisions		16,545,029		10,251,812		-		-		6,753,472		8,596,721		316,755		316,576		2,732,195		1,668,030		-		-		26,347,451	20,833,139
Deferred tax liabilities		201,461,102		177,178,521		10,812,791		13,419,881		2,860,251		4,538,425		12,001,108		-		141,771,503		146,431,483		-		-		368,906,755	341,568,310
Non-current provisions for employee benefits		14,609,221		12,334,488		2,382,287		2,216,852		-		-		22,056,756		21,953,569		672,652		-		-		-		39,720,916	36,504,909
Other non-current non-financial liabilities		15,380,152		17,626,394		24,827,460		27,711,972		1,249,800		9,012,870		11,708,837		22,168,785		-		-		(369,845)		-		52,796,404	76,520,021

EQUITY		2,939,888,984		3,027,001,250		35,378,069		84,398,847		465,620,304		547,000,840		912,020,793		880,989,598		503,843,013		493,425,433		(969,998,153)		(1,047,533,461)		3,886,753,010	3,985,282,507
Equity attributable to shareholders of Enersis		2,939,888,984		3,027,001,250		35,378,069		84,398,847		465,620,304		547,000,840		912,020,793		880,989,598		503,843,013		493,425,433		(969,998,153)		(1,047,533,461)		3,886,753,010	3,985,282,507
Issued capital		1,944,921,772		2,153,213,074		57,453,398		92,185,037		170,138,583		204,171,117		164,600,583		142,906,410		186,073,314		164,297,758		(1,035,015,732)		(1,003,883,359)		1,488,171,918	1,752,890,037
Retained earnings		1,100,970,411		1,140,321,396		(13,873,002)		(7,554,043)		176,225,150		202,644,366		524,280,383		128,464,532		75,744,989		70,760,796		27,093,929		303,782,125		1,890,441,860	1,838,419,172
Share premium		206,008,557		-		-		-		-		-		-		-		-		-		-		-		206,008,557	-
Treasury shares		-		-		-		-		-		-		-		-		-		-		-		-		-	-
Other equity interests		-		-		-		-		-		-		-		-		-		-		-		-		-	-
Other reserves		(312,011,756)		(266,533,220)		(8,202,327)		(232,147)		119,256,571		140,185,357		223,139,827		609,618,656		242,024,710		258,366,879		37,923,650		(347,432,227)		302,130,675	393,973,298

Non-controlling interests		-		-		-		-		-		-		-		-		-		-		-		-		-	-

Total Liabilities and Equity		4,458,904,213		4,639,924,178		347,541,119		433,929,915		672,193,440		829,315,263		1,849,027,622		1,632,263,297		866,977,201		888,208,186		(1,037,628,562)		(1,056,781,954)		7,157,015,033	7,366,858,885

F-105


Line of Business	Generation
Country	Chile						Argentina						Brazil						Colombia						Peru						Eliminations						Total
STATEMENT OF COMPREHENSIVE INCOME	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2010 ThCh$
REVENUES		1,156,117,994		1,257,995,225		1,345,370,795		347,671,353		395,296,464		358,089,711		361,855,124		309,049,119		359,211,026		580,151,107		498,568,875		507,526,498		282,124,274		239,841,441		211,263,618		(656,842)		(724,906)		(857,568)		2,727,263,010		2,700,026,218		2,780,604,080
Sales		1,093,513,127		1,244,969,978		1,315,430,658		344,621,942		395,107,435		351,429,303		361,855,124		306,693,874		351,386,168		579,490,649		496,505,095		507,148,312		280,813,676		239,031,927		210,800,064		(661,982)		(724,906)		(857,568)		2,659,632,536		2,681,583,403		2,735,336,937
Energy sales		1,031,596,364		1,214,467,888		1,286,727,887		341,123,404		389,963,331		345,706,935		294,359,410		253,753,923		258,243,192		578,673,437		495,453,014		506,194,881		273,293,947		233,663,702		202,614,778		-		-		-		2,519,046,562		2,587,301,858		2,599,487,673
Other sales		9,891,453		10,642,489		15,262,308		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		9,891,453		10,642,489		15,262,308
Other services rendered		52,025,310		19,859,601		13,440,463		3,498,538		5,144,104		5,722,368		67,495,714		52,939,951		93,142,976		817,212		1,052,081		953,431		7,519,729		5,368,225		8,185,286		(661,982)		(724,906)		(857,568)		130,694,521		83,639,056		120,586,956

Other operating revenue		62,604,867		13,025,247		29,940,137		3,049,411		189,029		6,660,408		-		2,355,245		7,824,858		660,458		2,063,780		378,186		1,310,598		809,514		463,554		5,140		-		-		67,630,474		18,442,815		45,267,143

SUPPLIES AND SERVICES		(764,220,474)		(679,798,692)		(666,388,433)		(281,490,845)		(315,717,397)		(267,824,397)		(131,313,182)		(55,607,090)		(109,560,464)		(171,182,696)		(134,977,823)		(176,746,281)		(111,094,930)		(86,884,090)		(80,240,613)		(5,140)		-		-		(1,459,307,267)		(1,272,985,092)		(1,300,760,188)

Energy purchases		(217,043,011)		(205,693,620)		(139,373,210)		(13,485,770)		(13,740,208)		(9,296,132)		(52,245,893)		(9,943,885)		(27,257,255)		(49,214,202)		(29,508,762)		(72,764,711)		(28,555,290)		(13,812,605)		(15,503,346)		1,220,179		-		-		(359,323,987)		(272,699,080)		(264,194,654)
Fuel consumption		(403,824,842)		(350,725,578)		(318,637,144)		(255,215,278)		(283,048,981)		(242,853,893)		(31,481,375)		(35,498,349)		(37,260,897)		(36,215,949)		(23,946,682)		(27,780,401)		(55,518,422)		(49,411,567)		(45,498,261)		-		-		-		(782,255,866)		(742,631,157)		(672,030,596)
Transport expenses		(146,788,041)		(115,056,998)		(161,189,862)		(4,074,257)		(8,165,583)		(3,636,524)		(16,161,314)		(16,353,299)		(5,098,408)		(57,311,261)		(54,452,560)		(50,431,204)		(19,718,720)		(16,393,695)		(12,778,594)		(1,225,319)		-		-		(245,278,912)		(210,422,135)		(233,134,592)
Other miscellaneous supplies and services		3,435,420		(8,322,496)		(47,188,217)		(8,715,540)		(10,762,625)		(12,037,848)		(31,424,600)		6,188,443		(39,943,904)		(28,441,284)		(27,069,819)		(25,769,965)		(7,302,498)		(7,266,223)		(6,460,412)		-		-		-		(72,448,502)		(47,232,720)		(131,400,346)

CONTRIBUTION MARGIN		391,897,520		578,196,533		678,982,362		66,180,508		79,579,067		90,265,314		230,541,942		253,442,029		249,650,562		408,968,411		363,591,052		330,780,217		171,029,344		152,957,351		131,023,005		(661,982)		(724,906)		(857,568)		1,267,955,743		1,427,041,126		1,479,843,892

Infrastructure work		8,472,680		3,954,056		-		-		-		-		713,161		244,254		-		4,133,486		2,187,900		688,024		157,020		18,593		-		-		-		-		13,476,347		6,404,803		688,024
Employee expenses		(55,832,919)		(42,826,606)		(31,556,880)		(22,442,565)		(19,020,797)		(14,457,685)		(11,545,260)		(12,425,160)		(11,622,887)		(15,935,879)		(13,009,393)		(12,219,664)		(12,729,281)		2,657,451		(6,161,429)		-		-		-		(118,485,904)		(84,624,505)		(76,018,545)
Other fixed operating expenses		(60,236,072)		(52,364,624)		(50,276,801)		(14,644,907)		(9,996,620)		(11,003,847)		(12,503,249)		(10,652,946)		(11,621,153)		(21,038,904)		(61,997,033)		(21,193,354)		(18,465,710)		(14,254,393)		(16,333,294)		661,982		724,906		857,568		(126,226,860)		(148,540,710)		(109,570,881)

GROSS OPERATING RESULT		284,301,209		486,959,359		597,148,681		29,093,036		50,561,650		64,803,782		207,206,594		230,608,177		226,406,522		376,127,114		290,772,526		298,055,223		139,991,373		141,379,002		108,528,282		-		-		-		1,036,719,326		1,200,280,714		1,294,942,490

Amortization and impairment losses		(108,549,387)		(88,155,103)		(84,379,198)		(23,217,258)		(16,647,907)		(18,093,427)		(26,462,161)		(27,115,088)		(67,594,458)		(38,466,238)		(37,264,422)		(36,572,942)		(38,938,854)		(36,724,390)		(38,208,869)		-		-		-		(235,633,898)		(205,906,910)		(244,848,894)

OPERATING INCOME		175,751,822		398,804,256		512,769,483		5,875,778		33,913,743		46,710,355		180,744,433		203,493,089		158,812,064		337,660,876		253,508,104		261,482,281		101,052,519		104,654,612		70,319,413		-		-		-		801,085,428		994,373,804		1,050,093,596

FINANCIAL RESULT		(62,789,726)		(47,157,682)		(62,503,182)		(37,240,393)		(24,064,353)		(9,499,131)		9,501,946		31,870,959		(20,035,955)		(38,974,600)		(44,412,198)		(35,898,815)		(16,903,421)		(10,596,299)		(14,738,535)		1,717,351		(2,173,731)		3,473,802		(144,688,843)		(96,533,304)		(139,201,816)
Financial income		6,276,879		15,047,206		4,880,575		2,968,512		6,318,260		1,504,063		24,959,636		62,448,962		19,217,791		5,210,427		6,440,538		3,441,874		1,230,290		862,313		455,981		(1,841,638)		(2,146,863)		(1,621,289)		38,804,106		88,970,416		27,878,995
Financial expenses		(68,632,987)		(57,750,591)		(70,389,036)		(23,674,921)		(20,995,238)		(18,112,699)		(18,097,957)		(49,265,315)		(36,376,407)		(43,917,815)		(50,600,130)		(39,269,219)		(18,088,798)		(10,794,337)		(15,505,355)		2,196,021		2,146,863		1,621,289		(170,216,457)		(187,258,748)		(178,031,427)
Gain (loss) from indexed assets and liabilities		(710,227)		(5,369,555)		(2,885,747)		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		(710,227)		(5,369,555)		(2,885,747)
Foreign currency exchange differences		276,609		915,258		5,891,026		(16,533,984)		(9,387,375)		7,109,505		2,640,267		18,687,312		(2,877,339)		(267,212)		(252,606)		(71,470)		(44,913)		(664,275)		310,839		1,362,968		(2,173,731)		3,473,802		(12,566,265)		7,124,583		13,836,363
Positive		8,164,603		16,349,908		12,258,950		7,926,758		4,805,473		19,544,626		8,385,976		27,309,335		27,014,846		407,595		370,895		184,162		3,196		19,821		805,044		(4,239,664)		(12,320,110)		(476,265)		20,648,464		36,535,322		59,331,363
Negative		(7,887,994)		(15,434,650)		(6,367,924)		(24,460,742)		(14,192,848)		(12,435,121)		(5,745,709)		(8,622,023)		(29,892,185)		(674,807)		(623,501)		(255,632)		(48,109)		(684,096)		(494,205)		5,602,632		10,146,379		3,950,067		(33,214,729)		(29,410,739)		(45,495,000)

Share of the profit (loss) from associates accounted for using the equity method		9,845,902		8,215,763		811,855		-		-		-		-		-		-		-		-		-		11,120,211		-		-		-		-		-		9,845,902		8,215,763		811,855
Negative Consolidation Difference		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Gain (loss) from other investments		158,288		539,283		234,251		498,738		498,877		-		-		-		-		-		-		-		-		-		-		-		-		-		657,026		1,038,160		234,251
Gain (loss) on the sale of property, plant, and equipment		(16,158)		478,619		24,894		2,032		-		-		-		-		23,169		187,055		70,187		1,127,732		562,330		426,771		455,621		-		-		-		735,259		975,577		1,631,416
Other expenses distinct from operating expenses		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-

NET INCOME BEFORE TAX		122,950,128		360,880,239		451,337,301		(30,863,845)		10,348,267		37,211,224		190,246,379		235,364,048		138,799,278		298,873,331		209,166,093		226,711,198		95,831,639		94,485,084		56,036,499		1,717,351		(2,173,731)		3,473,802		667,634,772		908,070,000		913,569,302

Income tax		(49,401,781)		(79,043,325)		(70,628,343)		(5,394,465)		(21,796,346)		(13,781,110)		(27,804,757)		(46,012,835)		(15,507,514)		(97,612,299)		(80,740,375)		(76,639,668)		(31,275,247)		(27,749,046)		(20,936,925)		-		-		-		(211,488,549)		(255,341,927)		(197,493,560)

NET INCOME AFTER TAX FROM CONTINUING OPERATIONS		73,548,347		281,836,914		380,708,958		(36,258,310)		(11,448,079)		23,430,114		162,441,622		189,351,213		123,291,764		201,261,032		128,425,718		150,071,530		64,556,392		66,736,038		35,099,574		1,717,351		(2,173,731)		3,473,802		456,146,223		652,728,073		716,075,742
Net income from discontinued operations		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-
NET INCOME		73,548,347		281,836,914		380,708,958		(36,258,310)		(11,448,079)		23,430,114		162,441,622		189,351,213		123,291,764		201,261,032		128,425,718		150,071,530		64,556,392		66,736,038		35,099,574		1,717,351		(2,173,731)		3,473,802		456,146,223		652,728,073		716,075,742

NET INCOME ATTRIBUTABLE TO		73,548,347		281,836,914		380,708,958		(36,258,310)		(11,448,079)		23,430,114		162,441,622		189,351,213		123,291,764		201,261,032		128,425,718		150,071,530		64,556,392		66,736,038		35,099,574		1,717,351		(2,173,731)		3,473,802		456,146,223		652,728,073		716,075,742
Shareholders of Enersis		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Non-controlling interests		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-		-

F-106

b) Distribution


Line of Business	Distribution
Country	Chile				Argentina				Brazil				Colombia				Peru				Eliminations				Total
ASSETS	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$
CURRENT ASSETS		161,687,282		193,667,154		75,393,801		84,947,442		396,065,371		424,487,557		259,622,744		239,448,013		83,158,205		73,305,844		(3,228,460)		(8,446,413)		972,698,943		1,007,409,597
Cash and cash equivalents		6,800,784		26,582,727		13,979,227		21,100,767		46,175,000		109,978,438		132,569,599		131,993,716		27,824,497		9,290,173		-		-		227,349,107		298,945,821
Other current financial assets		3		-		248,730		-		21,786,059		-		25,853,350		25,011		-		-		-		-		47,888,142		25,011
Other current non-financial assets		2,458,642		2,312,576		982,584		1,246,994		58,667,785		27,375,759		6,284,067		5,220,643		2,667,568		2,636,552		-		-		71,060,646		38,792,524
Trade and other current receivables		146,524,962		152,223,272		50,892,193		54,255,165		256,665,873		254,576,869		88,282,213		92,278,353		48,194,935		56,990,519		-		-		590,560,176		610,324,178
Accounts receivable from related companies		4,002,377		10,623,831		910,306		776,127		-		-		2,102,677		4,247,788		54,071		14,453		(3,228,460)		(8,446,413)		3,840,971		7,215,786
Inventories		1,452,915		1,924,748		3,234,106		3,138,669		634,171		1,252,066		3,769,260		5,682,049		4,390,026		4,357,382		-		-		13,480,478		16,354,914
Current tax assets		447,599		-		5,146,655		4,429,720		12,136,483		31,304,425		761,578		453		27,108		16,765		-		-		18,519,423		35,751,363

Non-current assets classified as held for sale and discontinued operations		-		-		-		-		-		-		-		-		-		-		-		-		-		-

NON-CURRENT ASSETS		1,141,771,230		1,116,514,950		249,249,898		272,099,510		1,813,358,782		1,994,823,050		977,719,287		960,707,757		456,528,437		434,005,821		-		-		4,638,627,634		4,778,151,088
Other non-current financial assets		25,110		25,176		86,201		-		375,227,434		-		7,015		9,099		3,183,912		2,792,448		-		-		378,529,672		2,826,723
Other non-current non-financial assets		333,644		229,343		580,733		885,726		59,325,193		79,626,762		1,074,740		-		-		-		-		-		61,314,310		80,741,831
Non-current receivables		6,863,063		3,699,470		1,666,444		1,378,682		32,901,738		251,693,307		10,377,397		10,485,477		-		-		-		-		51,808,642		267,256,936
Non-current accounts receivable from related companies		-		-		-		-		99,044		117,946		-		-		-		-		-		-		99,044		117,946
Investments accounted for using the equity method		510,734,949		503,579,522		25,684		31,383		-		-		1,716		76		-		-		-		-		510,762,349		503,610,981
Intangible assets other than goodwill		13,233,744		15,263,011		3,334,273		3,473,743		1,098,619,633		1,374,215,991		20,896,924		22,048,463		2,929,542		2,844,862		-		-		1,139,014,116		1,417,846,070
Goodwill		2,240,478		2,240,478		-		-		100,004,647		119,058,905		8,189,709		8,082,994		-		-		-		-		110,434,834		129,382,377
Property, plant, and equipment, net		608,238,796		583,180,744		243,556,563		266,329,976		18,163,438		20,746,848		897,059,859		882,070,391		450,414,983		428,368,511		-		-		2,217,433,639		2,180,696,470
Investment property		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Deferred tax assets		101,446		8,297,206		-		-		129,017,655		149,363,291		40,111,927		38,011,257		-		-		-		-		169,231,028		195,671,754

TOTAL ASSETS		1,303,458,512		1,310,182,104		324,643,699		357,046,952		2,209,424,153		2,419,310,607		1,237,342,031		1,200,155,770		539,686,642		507,311,665		(3,228,460)		(8,446,413)		5,611,326,577		5,785,560,685

F-107


Line of Business	Distribution
Country	Chile				Argentina				Brazil				Colombia				Peru				Eliminations				Total
LIABILITIES AND EQUITY	12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12-31-2012 ThCh$		12-31-2011 ThCh$		12- 31-2012 ThCh$		12-31-2011 ThCh$
CURRENT LIABILITIES		195,903,832		196,759,945		376,427,290		310,638,397		366,781,235		489,046,971		294,660,168		302,355,437		121,210,186		103,699,413		(3,228,460)		(8,446,413)		1,351,754,251		1,394,053,750
Other current financial liabilities		47		26,351		27,634,365		22,349,209		104,776,985		226,703,734		71,947,165		11,034,446		33,719,936		32,046,376		-		-		238,078,498		292,160,116
Trade and other current payables		100,344,207		137,937,525		290,202,271		235,366,718		203,340,459		183,352,939		142,380,436		172,660,428		43,394,348		44,810,969		-		-		779,661,721		774,128,579
Accounts payable to related companies		80,044,605		23,267,428		1,837,109		2,249,562		20,985,919		20,937,120		30,119,040		76,706,628		9,418,449		11,369,623		(3,228,460)		(8,446,413)		139,176,662		126,083,948
Other short-term provisions		9,182,725		9,088,010		28,531,366		21,423,408		1,559,596		6,801,936		-		-		5,042,674		5,913,838		-		-		44,316,361		43,227,192
Current tax liabilities		4,814,657		25,872,525		2,831,011		7,016,288		20,926,914		36,202,808		42,976,189		36,114,100		4,870,431		5,730,192		-		-		76,419,202		110,935,913
Current provisions for employee benefits		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Other current non-financial liabilities		1,517,591		568,106		25,391,168		22,233,212		15,191,362		15,048,434		7,237,338		5,839,835		24,764,348		3,828,415		-		-		74,101,807		47,518,002


Liabilities associated with non-current assets classified as held for sale and discontinued operations		-		-		-		-		-		-		-		-		-		-		-		-		-		-


NON-CURRENT LIABILITIES		70,857,009		52,473,555		17,990,925		41,497,104		815,506,536		870,301,120		330,110,898		397,178,370		202,239,407		210,609,245		-		-		1,436,704,775		1,572,059,394
Other non-current financial liabilities		-		-		2,929,147		25,941,484		439,191,002		478,627,090		234,412,181		295,721,421		147,679,985		152,604,148		-		-		824,212,315		952,894,143
Other non-current payables		-		-		-		905,643		14,081,540		13,155,174		-		-		-		-		-		-		14,081,540		14,060,817
Accounts payable to related companies		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Other long-term provisions		8,738,743		7,618,844		7,830,746		9,239,778		124,438,070		160,166,774		3,176,878		4,445,966		201,947		165,531		-		-		144,386,384		181,636,893
Deferred tax liabilities		16,134,411		22,742,572		-		-		110,169,354		63,153,516		18,955,626		19,717,371		51,244,001		56,914,980		-		-		196,503,392		162,528,439
Non-current provisions for employee benefits		18,784,699		17,289,987		4,631,912		5,410,199		127,516,473		149,352,163		66,022,050		62,774,313		1,564,125		-		-		-		218,519,259		234,826,662
Other non-current non-financial liabilities		27,199,156		4,822,152		2,599,120		-		110,097		5,846,403		7,544,163		14,519,299		1,549,349		924,586		-		-		39,001,885		26,112,440


EQUITY		1,036,697,671		1,060,948,604		(69,774,516)		4,911,451		1,027,136,382		1,059,962,516		612,570,965		500,621,963		216,237,049		193,003,007		-		-		2,822,867,551		2,819,447,541
Equity attributable to shareholders of Enersis		1,036,697,671		1,060,948,604		(69,774,516)		4,911,451		1,027,136,382		1,059,962,516		612,570,965		500,621,963		216,237,049		193,003,007		-		-		2,822,867,551		2,819,447,541
Issued capital		367,928,682		368,494,984		83,616,788		135,477,599		336,739,309		466,167,408		3,579,786		7,905,014		37,643,914		32,841,625		-		-		829,508,479		1,010,886,630
Retained earnings		1,027,496,558		978,146,893		(156,754,885)		(92,338,025)		244,654,424		72,309,174		107,753,937		(2,694,357)		60,254,433		1,623,660		-		-		1,283,404,467		957,047,345
Share premium		566,302		-		-		-		-		-		3,614,187		-		-		-		-		-		4,180,489		-
Treasury shares		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Other equity interests		-		-		-		-		-		-		-		-		-		-		-		-		-		-
Other reserves		(359,293,871)		(285,693,273)		3,363,581		(38,228,123)		445,742,649		521,485,934		497,623,055		495,411,306		118,338,702		158,537,722		-		-		705,774,116		851,513,566


Non-controlling interests		-		-		-		-		-		-		-		-		-		-		-		-		-		-


Total Liabilities and Equity		1,303,458,512		1,310,182,104		324,643,699		357,046,952		2,209,424,153		2,419,310,607		1,237,342,031		1,200,155,770		539,686,642		507,311,665		(3,228,460)		(8,446,413)		5,611,326,577		5,785,560,685

F-108


Line of Business	Distribution
Country	Chile				Argentina				Brazil				Colombia				Peru				Eliminations				Total
STATEMENT OF COMPREHENSIVE INCOME		12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$		12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$		12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$		12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$		12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$		12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$		12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$
REVENUE		984,738,418	1,046,190,998	1,016,997,495		321,242,024	279,724,815	295,538,314		1,880,664,677	1,976,715,786	1,987,041,550		888,586,388	815,486,660	785,889,588		385,013,476	329,309,210	307,158,970		-	-	-		4,460,244,983	4,447,427,469	4,392,625,917
Sales		974,543,004	1,035,360,191	1,003,001,004		309,297,973	271,566,142	287,867,341		1,716,445,896	1,784,693,095	1,717,875,184		853,070,370	783,614,400	757,935,491		364,412,134	311,980,876	286,654,227		-	-	-		4,217,769,377	4,187,214,704	4,053,333,247
Energy sales		859,734,418	936,062,746	900,798,434		292,980,498	251,678,813	268,829,105		1,609,908,784	1,661,700,350	1,648,205,624		737,017,110	677,266,087	657,681,311		354,534,983	303,303,904	279,239,525		-	-	-		3,854,175,793	3,830,011,900	3,754,753,999
Other sales		8,535,176	6,051,771	7,166,927		412,885	-	-		-	-	-		2,749,302	2,293,979	2,035,272		38,502	45,957	18,571		-	-	-		11,735,865	8,391,707	9,220,770
Other services rendered		106,273,410	93,245,674	95,035,643		15,904,590	19,887,329	19,038,236		106,537,112	122,992,745	69,669,560		113,303,958	104,054,334	98,218,908		9,838,649	8,631,015	7,396,131		-	-	-		351,857,719	348,811,097	289,358,478


Other operating revenue		10,195,414	10,830,807	13,996,491		11,944,051	8,158,673	7,670,973		164,218,781	192,022,691	269,166,366		35,516,018	31,872,260	27,954,097		20,601,342	17,328,334	20,504,743		-	-	-		242,475,606	260,212,765	339,292,670


SUPPLIES AND SERVICES		(728,000,745)	(803,854,371)	(788,044,087)		(175,422,082)	(141,879,982)	(142,565,611)		(1,247,583,156)	(1,297,135,167)	(1,310,974,462)		(480,431,128)	(451,191,503)	(426,625,508)		(252,013,491)	(210,904,949)	(193,646,086)		-	-	-		(2,883,450,602)	(2,904,965,972)	(2,861,855,754)
Energy purchases		(642,760,395)	(728,175,203)	(718,972,828)		(174,672,141)	(139,846,898)	(139,626,236)		(668,946,700)	(704,848,626)	(644,017,840)		(361,234,167)	(338,121,156)	(317,529,068)		(228,550,090)	(188,535,528)	(168,095,978)		-	-	-		(2,076,163,493)	(2,099,527,411)	(1,988,241,950)
Fuel consumption		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-
Transport expenses		(59,678,207)	(52,701,930)	(45,459,555)		(570,898)	(978,324)	(1,239,345)		(128,233,904)	(92,384,968)	(88,561,822)		(84,396,395)	(82,215,432)	(81,668,944)		-	(1,052)	-		-	-	-		(272,879,404)	(228,281,706)	(216,929,666)
Other miscellaneous supplies and services		(25,562,143)	(22,977,238)	(23,611,704)		(179,043)	(1,054,760)	(1,700,030)		(450,402,552)	(499,901,573)	(578,394,800)		(34,800,566)	(30,854,915)	(27,427,496)		(23,463,401)	(22,368,369)	(25,550,108)		-	-	-		(534,407,705)	(577,156,855)	(656,684,138)


CONTRIBUTION MARGIN		256,737,673	242,336,627	228,953,408		145,819,942	137,844,833	152,972,703		633,081,521	679,580,619	676,067,088		408,155,260	364,295,157	359,264,080		132,999,985	118,404,261	113,512,884		-	-	-		1,576,794,381	1,542,461,497	1,530,770,163


Infrastructure work		2,794,597	2,776,876	2,524,049		12,470,077	12,146,533	8,296,765		15,028,449	17,886,043	18,128,254		2,550,333	4,309,814	3,734,991		2,533,884	2,211,736	2,058,678		-	-	-		35,377,340	39,331,002	34,742,737
Employee expenses		(28,098,186)	(29,792,819)	(24,818,903)		(96,765,119)	(87,034,352)	(63,168,597)		(88,652,016)	(92,462,436)	(86,726,523)		(33,892,353)	(33,383,134)	(30,266,521)		(18,344,299)	(9,745,039)	(10,830,327)		-	-	-		(265,751,973)	(252,417,780)	(215,810,871)
Other fixed operating expenses		(64,211,702)	(60,852,918)	(64,729,067)		(99,917,490)	(78,690,268)	(77,589,301)		(137,882,458)	(146,412,225)	(144,659,664)		(62,716,075)	(85,303,430)	(61,109,969)		(22,294,925)	(18,518,662)	(18,333,017)		-	-	-		(387,022,650)	(389,777,503)	(366,421,018)


GROSS OPERATING RESULT		167,222,382	154,467,766	141,929,487		(38,392,590)	(15,733,254)	20,511,570		421,575,496	458,592,001	462,809,155		314,097,165	249,918,407	271,622,581		94,894,645	92,352,296	86,408,218		-	-	-		959,397,098	939,597,216	983,281,011


Amortization and impairment losses		(33,847,508)	(34,783,079)	(30,162,735)		(15,709,843)	(121,436,654)	(16,567,619)		(116,854,115)	(103,946,132)	(158,955,424)		(68,912,852)	(64,456,300)	(64,400,224)		(24,826,003)	(22,452,740)	(21,459,798)		-	-	-		(260,150,321)	(347,074,905)	(291,545,800)


OPERATING INCOME		133,374,874	119,684,687	111,766,752		(54,102,433)	(137,169,908)	3,943,951		304,721,381	354,645,869	303,853,731		245,184,313	185,462,107	207,222,357		70,068,642	69,899,556	64,948,420		-	-	-		699,246,777	592,522,311	691,735,211


FINANCIAL RESULT		9,223,776	10,648,013	2,470,113		(29,719,535)	(7,990,001)	(6,198,811)		12,072,874	(72,935,412)	(54,257,621)		(26,782,848)	(31,913,547)	(26,452,173)		(11,503,704)	(12,080,615)	(10,893,433)		29,726	60,038	700,563		(46,679,711)	(114,211,524)	(94,631,362)
Financial income		10,291,434	15,874,126	10,576,373		5,357,720	6,538,668	9,324,258		187,428,283	97,925,921	101,888,814		8,909,807	5,531,446	9,289,334		3,799,957	1,846,358	1,612,612		1	-	-		215,787,202	127,716,519	132,691,391
Financial expenses		(2,281,297)	(4,383,448)	(8,048,514)		(35,873,442)	(15,352,367)	(16,070,345)		(176,142,663)	(171,235,373)	(155,096,284)		(35,774,410)	(37,469,524)	(35,637,190)		(15,535,299)	(14,114,310)	(12,538,319)		-	-	-		(265,607,111)	(242,555,022)	(227,390,652)
Gain (loss) from indexed assets and liabilities		1,204,984	42,067	153,805		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		1,204,984	42,067	153,805
Foreign currency exchange differences		8,655	(884,732)	(211,551)		796,187	823,698	547,276		787,254	374,040	(1,050,151)		81,755	24,531	(104,317)		231,638	187,337	32,274		29,725	60,038	700,563		1,935,214	584,912	(85,906)
Positive		745,506	798,025	2,679,429		1,113,208	1,121,128	617,720		841,360	2,081,506	3,249,786		335,460	328,173	604,900		930,908	562,888	308,495		(261,497)	60,038	(204,474)		3,704,945	4,951,758	7,255,856
Negative		(736,851)	(1,682,757)	(2,890,980)		(317,021)	(297,430)	(70,444)		(54,106)	(1,707,466)	(4,299,937)		(253,705)	(303,642)	(709,217)		(699,270)	(375,551)	(276,221)		291,222	-	905,037		(1,769,731)	(4,366,846)	(7,341,762)


Share of the profit (loss) from associates accounted for using the equity method		-	-	-		310	468	911		-	-	-		-	-	-		-	-	-		-	-	-		310	468	911
Negative consolidation difference		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-
Gain (loss) from other investments		-	-	-		80,290	-	-		-	-	-		-	70	-		-	-	-		-	-	-		80,290	70	-
Gain (loss) on sale of property, plant, and equipment		(173,274)	(4,305)	(3,349)		-	-	-		1,983,259	-	-		(724,804)	(301,065)	1,389,720		(97,875)	(8,420)	(21,095)		-	-	-		987,306	(313,790)	1,365,276
Other expenses distinct from operating expenses		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-


NET INCOME BEFORE TAX		142,425,376	130,328,395	114,233,516		(83,741,368)	(145,159,441)	(2,253,949)		318,777,514	281,710,457	249,596,110		217,676,661	153,247,565	182,159,904		58,467,063	57,810,521	54,033,892		29,726	60,038	700,563		653,634,972	477,997,535	598,470,036


Income tax		(24,732,758)	(33,614,812)	(23,402,198)		2,935,069	(12,248,134)	635,038		(100,740,767)	(75,932,075)	(43,566,137)		(72,376,252)	(62,216,531)	(56,459,150)		(18,540,672)	(16,517,066)	(18,808,290)		-	-	-		(213,455,380)	(200,528,618)	(141,600,737)


NET INCOME AFTER TAX FROM CONTINUING OPERATIONS		117,692,618	96,713,583	90,831,318		(80,806,299)	(157,407,575)	(1,618,911)		218,036,747	205,778,382	206,029,973		145,300,409	91,031,034	125,700,754		39,926,391	41,293,455	35,225,602		29,726	60,038	700,563		440,179,592	277,468,917	456,869,299
Net income from discontinued operations		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-
NET INCOME		117,692,618	96,713,583	90,831,318		(80,806,299)	(157,407,575)	(1,618,911)		218,036,747	205,778,382	206,029,973		145,300,409	91,031,034	125,700,754		39,926,391	41,293,455	35,225,602		29,726	60,038	700,563		440,179,592	277,468,917	456,869,299


NET INCOME ATTRIBUTABLE TO		117,692,618	96,713,583	90,831,318		(80,806,299)	(157,407,575)	(1,618,911)		218,036,747	205,778,382	206,029,973		145,300,409	91,031,034	125,700,754		39,926,391	41,293,455	35,225,602		29,726	60,038	700,563		440,179,592	277,468,917	456,869,299
Shareholders of Enersis		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-
Non-controlling interests		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-		-	-	-

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34.

THIRD PARTY GUARANTEES, OTHER CONTINGENT ASSETS AND LIABILITIES, AND OTHER COMMITMENTS

34.1

Direct guarantees


Creditor of Guarantee	Debtor		Type of Guarantee	Assets Committed				Balance Pending at December 31					Guarantees Released
	Debtor			Type	Currency	Accounting Value		Balance Pending at December 31					Guarantees Released
	Name	Relationship		Type	Currency	Accounting Value		Currency	2012		2011		2013		Assets		2014		Assets		2015		Assets
Mitsubishi	Endesa Costanera	Creditor	Pledge	Combined cycle	ThCh$		39,223,807	ThCh$		67,546,660		73,262,031		-		-		-		-		-		-
Credit Suisse First Boston	Endesa Costanera	Creditor	Pledge	Combined cycle	ThCh$		17,906,111	ThCh$		4,799,600		5,192,000		-		-		-		-		-		-
Banco de la Nación Argentina	Endesa Costanera	Creditor	Pledge on collection and others	Collection CAMMESA accounts	ThCh$		2,902,660	ThCh$		2,902,660		-		-		-		-		-		-		-
Citibank N.A. / Santander Río	Edesur	Creditor	Pledge	Money deposit	ThCh$		6,474,660	ThCh$		5,686,862		-		-		-		-		-		-		-
Various Creditors	Edegel	Creditor	Pledge	Real estate and equipment	ThCh$		-	ThCh$		-		7,127,904		-		-		-		-		-		-
Scotiabank	Chinango	Creditor	Pledge	Collection flows	ThCh$		-	ThCh$		-		16,095,200		-		-		-		-		-		-
Banco Santander (Guarantee Agent)	G.N.L. Quintero	Affiliate	Pledge	Shares	ThCh$		-	ThCh$		97,034,059		109,265,974		-		-		-		-		-		-
Deutsche Bank / Santander Benelux	Enersis S.A.	Creditor	Deposit account	Deposit account	ThCh$		27,045,746	ThCh$		60,774,330		55,264,828		-		-		-		-		-		-
Various Creditors	Ampla S.A.	Creditor	Pledge on collection and others		ThCh$		3,154,334	ThCh$		122,400,013		140,483,626		-		-		-		-		-		-
Various Creditors	Coelce S.A.	Creditor	Pledge on collection and others		ThCh$		13,037,542	ThCh$		77,984,021		99,126,606		-		-		-		-		-		-
International Finance Corporation	CGT Fortaleza S.A.	Creditor	Mortgage and pledge	Real estate and equipment	ThCh$		118,013,487	ThCh$		29,477,645		38,087,401		-		-		-		-		-		-

As of December 31, 2012, Enersis S.A. had future energy purchase commitments amounting toThCh$ 24,179,632,682 (ThCh$ 29,249,750,127 as of December 31, 2011).

34.2

Indirect guarantees

Creditor

Guarantee

Debtor

Assets Committed

Balance Pending

Guarantees Released

Type of

Guarantee

Currency

Accounting

Value

at December 31

Name

Relationship

Currency

2012

2011

2013

Assets

2014

Assets

2015

2016

Bank loan cells

CIEN

Subsidiary

Guarantee

ThCh$

55,410,663

Bonds and bank loans

Chinango

Subsidiary

Guarantee

ThCh$

15,245,788

ThCh$

15,245,788

21,553,733

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34.3

Lawsuits and Arbitrations Proceedings

As of the date of these consolidated financial statements, the most relevant litigation involving Enersis and is affiliates are as follows:

1.- Law 25,561 on Public Emergency and Reform to the Currency System, enacted on January 6, 2002 by the Argentine authorities, voided certain provisions of the concession agreement of Enersis’ subsidiary Edesur. That law also required that utility concession agreements be renegotiated within a reasonable timeframe to adjust them in light of the new situation. However, failure to renegotiate Edesur’s concession agreement prompted Enersis S.A., Chilectra S.A., Endesa Chile and Elesur S.A. (now Chilectra S.A.) (Collectively, the “Claimants”) to file an arbitration petition in 2003 under the Treaty for the Promotion and Protection of Chilean-Argentine Investments with the International Center for Settlement of Investment Disputes (ICSID). The statement of claim principally requested that the ICSID declare that Edesur’s assets had been expropriated and that Edesur suffered damages totaling US$ 1,306,875,960; In addition, the Claimants requested that ICSID award indemnification caused to Edesur’s assets due to lack of fair and equitable treatment, totaling US$ 318,780,600. Claimants also seek, with respect to both claims, compounded annual interest of 6.9% per annum; The Claimants also claimed the sums resulting from the damages caused as from July 1, 2004. Finally, the claimants also demanded US$ 102,164,683 for Elesur S.A. (now Chilectra S.A.) due to a lower price received on a sale of its shares as a result of the alleged expropriation. In 2005, the Argentine authorities and Edesur executed a Letter of Understanding, which was not objected to by the Argentine parliament and was later ratified by the Executive Branch. The Letter of Understanding amends and supplements the terms and conditions of the concession agreement, introducing adjusted rates, first during a transitional period and then under a Comprehensive Rate Review that will establish the conditions for a regular 5-year rate period. Arbitration has been stayed since March 2006 in accordance with the terms of the Letter of Understanding, which stay has been renewed annually at the Claimants’ request. On October 13, 2010, the arbitral panel advised that the proceedings were stayed until October 6, 2011. Once this stay expired, the arbitral panel was to ask the parties to provide a status report on the negotiation process in accordance with the Letter of Understanding, which as of this date has not yet taken place.

In October 2010, arbitrator Robert Volterra tendered his resignation. Applicable regulations required the Claimants to designate a replacement within 45 days as from the notice sent by the Clerk’s Office; however, the Claimants asked that the proceeding also be stayed with regard to the designation of the substitute arbitrator, to which the Argentine Republic consented.

2.- Meridional Servicios, Emprendimientos y Participaciones (“Meridional”) is a company whose only assets are the litigation rights which were acquired from the construction companies Mistral and CIVEL, which entered into a civil works contract with Centrais Elétricas Fluminense S.A. (“CELF”). The contract was terminated by CELF before its privatization process started, which eventually led to the creation of Enersis’ Brazilian distribution Related Company Ampla. Since CELF’s assets were transferred to Ampla during the privatization, Meridional sued Ampla in 1998 contending that the assets had been transferred in fraud of their rights. Ampla only acquired assets from CELF, but is not its successor-in-interest since CELF, a state-owned company, still exists and maintains its legal capacity. The plaintiff demanded payment of pending invoices and contractual penalties for termination of the civil works contract. In March 2009, the court decided in favor of Meridional, and Ampla and the State of Rio de Janeiro filed appeals. On December 15, 2009, the State Court accepted the appeal and overturned the lower court’s decision obtained by the construction company in March 2009, in Ampla´s favor. Meridional filed an appeal, which was denied. In July 2010, Meridional filed a new Appeal under Specific Court Regulations (Agravo Regimental) with the Superior Court of Justice of Brazil, which the court also denied in late August 2010, ruling it was groundless. In order to overturn such decision, Meridional filed a Petition for Writ of Mandamus (Mandado de Seguranca), which was also denied. In June 2011, Meridional filed an Appeal to Request Clarification of the Decision (Embargos de Declaraçäo) in order to clarify an omission by the Superior Court of Justice in the decision on the Petition of Writ of Mandamus, which was not accepted by the court. Against this decision, Meridional filed a Regular Appeal (Recurso Ordinario) before the Superior Court of Justice (in Brasilia). On August 30, 2011 the proceeding was sent to the Public Prosecutor’s Office and, on December 13, 2011, to the Minister Rapporteur of the Superior Court of Justice (Ministro Relator del Tribunal Superior de Justiça (STJ)). On March 28, 2012 the Minister Rapporteur decided the Regular Appeal in favor of Meridional. Ampla and the State of Rio de Janeiro filed an Appeal under Specific Court Regulations against the Reporting Justice’s decision, which was accepted by the First Court Room of the Superior Court of Justice on August 28, 2012, determining that the Regular Appeal of the Petition of Writ of Mandamus must be submitted to the full Court and not only by one single Justice. The plaintiff (Meridional) challenged the decision. The sentence of August 28, 2012 was published on December 10, 2012, once the Amendment of Judgment (Embargos Declaração) has been filed by Ampla to remedy the existing error in its publication, in order to avoid future divergence. The amount involved in this trial is estimated to be of approximately US$434.65 million.

3.- Companhia Brasileira de Antibióticos (“CIBRAN”) filed suit against Enersis’ Brazilian distribution subsidiary, Ampla, for damages for the loss of products and raw materials, machinery breakdown, among other things, which allegedly occurred as a result of poor service provided by Ampla between 1987 and May 1994, CIBRAN is also seeking payment of punitive damages. This litigation is in the trial stage and has been joined with various other claims filed by Cibran against Ampla, including five other actions for smaller amounts based on power outages allegedly caused by Ampla. The judge decided to conduct a single expert assessment for these various claims, which was in part adverse to Ampla. On March 4, 2011, Ampla challenged the expert assessment, seeking its annulment, pointing out various contradictions in which the expert’s assessment and demanded that a new assessment be conducted. On March 2, 2012, the parties expressed their opinion on the expert

F-111

assessment and on March 20, 2012, the proceeding went before the Public Ministry. On December 19, 2012 AMPLA has reiterated that a second expert review be performed, due to errors and contractions of the expert, in the expert proceeding previously filed. The amount involved for all these cases is estimated at approximately US$56.29 million.

4.- In October 2009, Tractebel Energía S.A. sued CIEN claiming an alleged breach of the “Purchase & Sale Agreement for 300 MW of Firm Capacity with related energy originating from Argentina” entered into in 1999 by and between CIEN and Centrais Geradoras do Sul do Brasil S.A (Gerasul — presently Tractebel Energia). Tractebel asked the court to order that CIEN pay a rescission penalty of R$ 117,666,976.00 (approximately US$ 57.58 million) plus other fines due to the non-availability of “firm capacity and related energy,” and asked the court to determine those other fines in its ruling. The breach allegedly occurred due to a failure by CIEN to assure the availability of capacity contractually agreed with Tractebel over the 20-year period, which allegedly took place beginning in March 2005. In November 2009 CIEN answered the lawsuit, arguing that this unavailability was caused by the “Argentine Crisis,” since CIEN imports all the energy it delivers — when needed - to Tractebel. CIEN also argued that the “Argentine Crisis” was an extraordinary event in which CIEN was not involved to any extent, and that this situation was even acknowledged by the Brazilian authorities at the time. In May 2010, Tractebel notified CIEN via a written statement that it intended to exercise its step-in rights in Line I (30%). The proceeding is currently at the trial stage. In October 2011, Tractebel filed its reply to the filings submitted by CIEN, and the lawsuit was sent to the judge in November for him to decide on the lawsuit and determine if he will provide CIEN the opportunity to make any statements it feels necessary or to begin discovery. On June 11, 2012 Cien filed a presentation to the court of law reinforcing the argument of the Argentinean crisis, attaching reports from Argentinean legal experts and from the School of Engineering of the University of Buenos Aires. On October 22, 2012, the judge accepted CIEN’s request of joining this legal suit with the lawsuit filed by CIEN against Tractebel in 2001, which discussed the collection of values relative to the rate of exchange and taxing trigger (“gatillo”). On November 29, 2012, Tractebel filed an Amendment of Judgment against such sentence, which is pending resolution.

5.- Furnas Centrais Eletricas S.A. filed a suit against CIEN, which was served on June 15, 2010, based on CIEN’s alleged breach of Purchase & Sale Agreement for 700 MW of Firm capacity with related energy originating from Argentina. The agreement was signed in May 1998, with CIEN committing itself to purchase electricity in the Wholesale Electric Market of the Argentine Republic (Mercado Eléctrico Mayorista de la República Argentina), and transporting it from the Argentine electric system through the Interconnection Transmission System (Sistema de Transmissão de Interliga ão), to be made available in Brazil at the Itá substation. The contract has a 20-year term effective June 21, 2000. On April 11, 2005, CIEN informed Furnas that it was unable to fulfill the agreement due to events beyond its control, alleging force majeure. Consequently, on April 14, 2005, Furnas notified CIEN that it rejected the force majeure allegations. Furnas is requesting that CIEN pay R$ 520,800,659 (approximately US$ 254.85 million) as a rescission penalty as provided for in the agreement, as adjusted according to the terms of such agreement, plus interest from the date of filing of the claim until actual payment, as well as other penalties based on the lack of availability of the contracted capacity, and other damages to be determined upon the final decision. Discovery in the lawsuit is now completed and, in respect of the foreign language documents presented by CIEN, the trial judge of first instance determined that those documents would be excluded from the lawsuit, which decision was confirmed on June 14, 2011 by the 12th. Civil Section of the State Court. CIEN has filed a Special Appeal (Recurso Especial) against this decision, which will be decided by the Superior Court of Justice in Brasilia. At present, the decision of such appeal is pending.

6.- In December 2001, the article of the Brazilian Federal Constitution used by Ampla to claim an exemption from the COFINS tax (Contribuição para o Financiamento da Seguridade Social) was amended, which resulted in the sale of electricity being subject to tax. Ampla only started to pay the COFINS tax beginning in April 2002 because it believed that the changes in law are effective 90 days after they are published. However, the Federal Revenue (Receita Federal) argued that this constitutional norm applies only to amendments at the level of statutes, but not to those made to the Federal Constitution itself, which would apply immediately. In November 2007, the appeal was decided at the administrative appeals level (Consejo de Contribuyentes, Taxpayers Council), against AMPLA. In October 2008, Ampla filed a special appeal that was denied. Therefore, this aspect of the administrative action was concluded unfavorably for Ampla. However, a separate issue (is still pending before the administrative body which ussue was ruled in favor of Ampla by the Taxpayer council but), was opened for review at the administrative level). Because this second issue still pending before the administrative body, judicial review remain pending. The amount involved is US$87.81 million.

7.- In order to fund its investment in Coelce in 1998, Ampla issued long-term debt abroad through instruments called Fixed Rate Notes (FRNs) that were under a special fiscal system through which interests received by non-resident subscribers were exempt from taxation in Brazil, when the debt was issued with a minimum maturity of 8 years. In 2005 the Brazilian Taxing Administration notified Ampla through a Minute that it has declared the non-application of such special fiscal system since it understood that Ampla had amortized the FRNs implicity, before the maturity was complied with, because Ampla had gotten financing in Brazil allocated to financing the FRN subscribers. In Ampla’s opinion, they are two independent legally valid transaction. The non-application of the system assumes that Ampla was non-compliant on retaining the tax and entering it on interests paid to non-resident subscribers. The Minute was appealed and in 2007 the Consejo de Contribuyentes annulled it. However, the Brazilian Taxing Administration contested this decision before the Superior Chamber of Fiscal Resources (Cámara Superior de Recursos Fiscales), the final administrative instance and on November 6, 2012 entered judgment against Ampla. The decision was notified to Ampla on December 21 and on December 28, Ampla filed clarification recourse before the Chamber in order to clarify a final resolution regarding contradictory points of the sentence and that the relevant defense arguments omitted be incorporated. In case of confirming the resolution by the Higher Chamber of Fiscal Resources, Ampla will recur before the Courts of Law. The amount of this lawsuit is US$401.22 million.

F-112

8.- In 2002, the State of Rio de Janeiro issued a decree establishing that the ICMS (Imposto sobre operações relativas a circulação de mercadorias e sobre prestações de serviços de transporte interestadual, intermunicipal e de comunicação) should be calculated and paid on the 10th, 20th and 30th days of the same month of the accrual. Ampla continued entering ICMS in accordance with the previous system (on the 5th day of the month following its accrual) and did not adopt this system between September 2002 and February 2005 due to cash flow problems. Additionally, Ampla filed a lawsuit to determine the constitutionality of the demand of the advanced revenue. Ampla starting from March 2005, has been adopting the ICMS according to the new system. In September 2005 the State of Rio de Janeiro issued a resolution against Ampla to collect the fine on late payments, set in the aforementioned Decree of 2002. Ampla appealed the resolution before the Administrative Courts of Law, based on the fiscal Amnesty Laws of the State of Río de Janeiro published in 2004, 2005 and 2006 (condoning interests and penalties if the taxpayer paid for the pending taxes). Ampla alleges that if the aforementioned fiscal amnesties for Ampla do not turn out to be applicable, the law would treat taxpayers that are delayed only a few pays in the payment of taxes (Ampla’s case) in a worse manner than those who, formally, later recurred to different fiscal amnesties to regulate their taxing situation through paying taxes that were not paid in the past. The En Banc Council (a special body within the Taxpayers Council, last administrative instance) on May 9, 2012 entered judgment against Ampla. Which was notified on August 29, 2012. Ampla decided to adopt an extraordinary strategy and requested a review of the decision by the administrative authorities based on the amnesty law (review proceeding contemplated by the 2006 Amnesty Law). The request was filed before the competent entity of the State Public Treasury. Thereafter, the petition was forwarded to the aforementioned entity and successively before the Governor of Rio de Janeiro (instance contemplated by tax and administrative law, for decisions based on equity, in our case, under the argument of taxpayers that did not pay the tax being in a better situation than Ampla’s). A decision on the request filed is pending, which is why the debt should be suspended pending the final analysis of the proceeding in the administrative scope. In November 2012 the State of Rio de Janeiro has inscribed the debt in the public register as past due, implying the need to contribute the guarantee of 140% on November 12, of the taxable debt in order to continue receiving public funds. Once such decision is issued, probably unfavorable, Ampla will recur to the judicial branch. The amount is of US$ 102.96 million.

9.- In late 2002, Enersis’ Brazilian generation subsidiary CGTF filed a petition against the Federal Revenue seeking an acknowledgment that the assets imported for the turbo-generator units should be classified under “Other Generators” in order to be eligible for a 0% Import Tax (Imposto de Importação, or II) and for Industrial Products Tax (Imposto sobre Produtos Industrializados, or IPI). Endesa Fortaleza also obtained an interlocutory resolution in its favor allowing to clear goods from customs with a 0% duty, after depositing a bond with the court. Endesa Fortaleza obtained a favorable resolution in the administrative instance and in the Second Judicial Instance. In 2009, the Federal Revenue filed clarification recourse against the sentence of the Second instance that was sentenced in favor of Endesa Fortaleza. In March 2010, the Federal Revenue filed a Special Appeal (Recurso Especial) with the Superior Court of Justice in Brasilia. In 2011, the Federal Revenue was notified that its Regular Appeal had been denied, and the Federal Revenue appealed this decision. The bond deposited in the court must continue as guarantee for the proceeding until final sentence is filed. The amount is US$ 38.19 million.

10.- In 2005, three lawsuits were filed against Endesa Chile, the National Treasury and the Chilean General Water Affairs Bureau (the “DGA”), which lawsuit are currently being treated as a single proceeding, requesting that DGA Resolution 134, which established non-consumptive water rights in favor of Endesa Chile to build the Neltume hydroelectric station project, be declared null as a matter of public policy, with compensation for damages. Alternatively, damages were sought for the detriment allegedly sustained by the plaintiffs due to the loss of their status as riparian owners along Pirehueico Lake, as well as for the devaluation of their properties. The defendants have rejected these allegations, contending that the resolution complies with all legal requirements, and that the exercise of this right does not cause any detriment to the plaintiffs, among other arguments. The sums involved in these suits are undetermined. This case was joined with two other cases: the first one is captioned “Arrieta v. the State and Others” in the 9th Civil Court, docket 15279-2005 and the second is captioned “Jordán v. the State and Others,” in the 10th Civil Court, docket 1608-2005. With regard to these cases, an injunction has been ordered against entering into any acts and contracts concerning Endesa Chile’s water rights related to the Neltume project. In terms of the status, the regular evidence period has ended. The expert report has been filed, and Endesa requested its annulment, since the recognition hearing had not been carried out. The National Treasury and DGA became a part of the above annulment incident.

11.- Two legal proceedings were initiated in 2008 and 2011 against Empresa Eléctrica Pangue S.A. (whose legal successor is currently San Isidro S.A., a subsidiary of Endesa Chile), where the plaintiffs sought damages that they allege were due to flooding caused by the operations of the Pangue hydroelectric station, in particular related to spills caused in July 2006. Pangue S.A. has responded to such lawsuits arguing that its operation of the power station was in accordance with existing regulations and that it acted with due diligence and care. Consequently, Pangue S.A. argues that there is no causal link between the floods and the spills caused by the station during the period in question. These proceedings are being reviewed in several courts. The amount claimed in one of these cases is equal to $ 30,000,000 (US$ 62,505) and the other is for an undetermined amount. In the first of these trials, on June 27, 2012, there was a first instance ruling filed, which rejects the claim filed in all its parts. The plaintiff has filed a recourse appeal against such sentence, which to date is still pending review by the court. In the other, the evidence period has ended and the company is waiting to hear the sentence issued. It is worth

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noting that these proceedings are covered by an insurance policy. The company management deems that, due to the prior judicial sentences in favor of Empresa Eléctrica Pangue S.A. in similar proceedings and the current amount of the proceedings currently in force (two) these trials will stop being informed.

12.- During 2010, three lawsuits for damages were filed against Endesa Chile by plaintiffs alleging that they were affected by the flooding of the Bio-Bio River in Region VIII. The plaintiffs sued Endesa Chile for losses caused by its deficient operation of the Ralco hydroelectric station during the flood. The plaintiffs are required to produce legal evidence proving the causal link between the operation of the Ralco hydroelectric station during the floods and the damages that the plaintiffs claim they sustained as a result of deficient facility operation. On March 27, 2012, there was a first instance ruling filed, which rejects the claim filed in all its parts. The plaintiff filed an appeal recourse, regarding which on August 28, 2012 the court reviewed the case. Afterwards, a constituent judge disqualified herself, annulling the court review of the case, ordering that such proceeding be carried out again, which to date is still pending. The amount involved in the three lawsuits totals Ch$ 14,610,042,700 (approximately US$ 30.44 million). The total risk of these proceedings is covered by an insurance policy.

13.- In July and September of 2010, Ingeniería y Construcción Madrid S.A. and Transportes Silva y Silva Limitada, respectively, filed separate lawsuits against Endesa Chile and the “DGA”, seeking to declare the annulment of DGA’s administrative resolution 134 that granted ENDESA CHILE’s water rights for the Neltume hydroelectric station. Similarly, Ingeniería y Construcción Madrid S.A. and Transportes Silva y Silva Limitada, respectively, each filed suits against DGA’s administrative resolution 732, that authorized the relocation of the water uptake point of such rights null as a matter of public policy. Ultimately, the plaintiffs attempted to demand payment for their water rights located in the area of influence of the hydraulic works for the future Neltume station. Endesa Chile has rejected these claims, contending that the plaintiffs are abusing the judicial process to prevent the construction of the station in order to obtain monetary compensation. As to the procedural status of the two lawsuits, in the discovery period has expired for the trial filed by Ingeniería y Construcción Madrid S.A. (Case No. 7036-2010), pending the resolution of the reconsideration recourse filed by Endesa Chile against a discovery resolution of a discovery nature. Regarding the other lawsuit (Case No. 6705-2010), which requested the annulment of DGA resolution 732, on March 12, 2012 a ruling was issued that declared the proceeding as abandoned. Afterwards, on June 27, 2012, Ingeniería y Construcción Madrid filed a similar lawsuit again before another Court of Law (Case No. C-15156-2012), proceeding that is pending the transfer to file the rejoinder. On the other hand filed by Transportes Silva y Silva Ltda., (Case No. 16025-2012), which contests DGA resolution 134, the proceeding was declared as abandoned. In another suit filed (Case No. 17916-2010), which requested the proceeding as abandoned, however it was denied, and an appeal was filed . This proceeding is pending the initiation of the discovery stage. All these lawsuits are for an undetermined amount.

14.- In 2001, a lawsuit was filed against Enersis Chile’s Colombian generation subsidiary Emgesa S.A. E.S.P., as well as Empresa de Energía de Bogotá S.A. E.S.P. (“EEB”) and Corporación Autónoma Regional de Cundinamarca (“CAR”), by the inhabitants of Sibaté, Department of Cundinamarca. The lawsuit seeks to make the defendants jointly and severally liable for the damages arising from the pollution of the El Muñá reservoir, as a result of Emgesa’s pumping of polluted waters from the Bogotá River. Emgesa has challenged these allegations, establishing that it is not liable for these damages, arguing, among other things, that it receives already polluted water, among other arguments. The plaintiffs’ initial demand was for $ 3,000,000,000 in thousands of Colombian pesos (approximately US$ 1,696,611 million). Emgesa petitioned for the joinder of approximately 60 public and private entities that also discharge their effluents into the Bogotá River or that otherwise have responsibility for the environmental management of the river basin, which is why the lawsuit was sent on to the State Council (Consejo de Estado), with remedies pending by these entities before this regulatory body. On June 29, 2010, the parties were notified of a motion filed by the attorney for the plaintiffs, whereby the plaintiffs sought to declare the acts of the Administrative Court of Cundinamarca since August 1, 2006 null, claiming that from that date such court lost the authority to hear the current process, since the Administrative Circuit Courts started to be in force, which were the competent courts to hear the class actions and popular legal suits in conformance with Law 472, dated 1998. Emgesa gave its timely opinion regarding the matter, claiming that such annulment request would be irrelevant and unlawful. Currently, the Third Section of the State Council has resolved to confirm the ruling of the Court that denied Emgesa’s impleader petition and joined various legal entities as defendants, including: Hospital Juan F. Copras, Refisal S.A., Tinzuque S.A., Emocables S.A., Cristalería Peldar S.A., Líquido Carbónico Colombiano S.A., Icollantas S.A. and Agrinal S.A. Also, the annulment request filed by the plaintiffs (inhabitant of Sibaté) was denied, although the State Council required the Administrative Court for Adversary Proceedings (Tribunal Contencioso Administrativo) to pass the case to the Administrative Courts of the Bogotá Circuit (Juzgados Administrativos del Circuito de Bogotá) so that they can continue their review. In June 2011, the Administrative Court for Adversary Proceedings issued a writ ruling that the lawsuit was passed to the Fifth Administrative Court of Bogotá (Juzgado Quinto Administrativo de Bogotá), which then in turn sent it to the State Council to resolve on appeal the writ of admission requested by Alpina. The State Council then resolved the appeal keeping the tie of Alpina to this case and the proceeding is pending before the Fifth Administrative Court of Bogotá to continue its course.

15.- The Peruvian tax authority, SUNAT (Superintendencia Nacional de Aduanas y de Administración Tributaria), through Tax and Fine Resolutions (Resoluciones de Impuestos y Multas) issued in 2001, questioned Edegel’s method used in accounting for depreciation of Edegel’s revalued assets. In January 2002, Edegel filed a petition (recurso de reclamacion) against these resolutions, which SUNAT dismissed as groundless. Edegel filed an appeal with the Tax Court (Tribunal Fiscal), which ruled in its favor in 2004, upholding (i) its right to depreciate the goodwill obtained from revaluating the assets, based on the fact that Edegel had a statutory stability agreement (convenio de estabilidad jurídica), and (ii) the inapplicability of Rule VIII of the Tax Code, since there was no fraud or simulation involved. Also, the resolution provided that SUNAT had to verify that the

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revaluation of assets was not done at more than fair market value. From that date, Edegel has received several notifications from SUNAT requesting a determination of the revaluation surplus and the tax payable. In January 2006, a complaint was filed, followed by an appeal filed in 2008 against the resolution of SUNAT’s claim before the Tax Court. In February 2012, the Tax Court ruled in a last administrative instance on the Edegel litigation for income taxes for the 1999 accounting period regarding the voluntary reevaluation of assets. The Court of Law has sentenced in favor of Edegel with respect to Central Huinco (Huinco Power Plant) (civil works) and Central Matucana (Matucana Power Plant) (civil works, equipment and machinery and other assets) and against Edegel with respect to the other power plants (Santa Rosa, Callahuanca, Moyopampa and Huampaní), providing that the SUNAT “will proceed to the debt recalculation.”

In May 2012, Edegel filed a Contentious Administrative Claim (Demanda Contencioso Administrativa, or DCA,) against the ruling of the Tax Court. In June 2012: Edegel filed before the SUNAT a writ for the recalculation of the debt ordered by the Tax Court and that pertains to resettlement by the SUNAT. On June 19, 2012, Edegel received the Resolution of Intendancy No. 0150150001103, which established the recalculation made by the SUNAT regarding the tax debt. In June 26, 2012, Edegel made a partial payment of the updated debt to such date, other than the part referring to the Workers’ Profit Sharing. It is worth noting that payment has been made based on the criteria adopted by the Taxing Court of Law in record IR 1999. Such payment has not meant waiving any attempt made by Edegel, i.e., the litigation is maintained. In July 2012, Edegel received a Resolution of the Intendancy of the SUNAT that disregards the recalculation. Edegel filed a partial recourse appeal against the SUNAT resolution. The appeal was taken before the Tax Court for its resolution. In August 2012, the Judge admitted the DCA for processing and ordered its transfer so that the Tax Court and SUNAT can resolve the DCA. In October 2012, the Judge acknowledges the DCA as contested, both by the Tax Court and SUNAT. In summary, the status of the litigation is as follows: Regarding the 1999 accounting period, a ruling was issued which was partially favorable to Edegel providing that the SUNAT must perform the debt recalculation. In the Tax Court, the resolution of the appeal against the Resolution of the Intendancy of the SUNAT, which recalculated the debt, is still pending. In the Judicial Branch (Poder Judicial), the DCA has been admitted for processing and the transfer is still pending resolution by the Tax Court. Regarding the 2000 and 2001 accounting periods, verbal reports and written allegations were filed and the decision of the Tax Court is still pending. Resolution by the Tax Court is pending. The sums of the amounts at issue are of approximately US$ 36.55 million.

16.- In 2004, 2005 and 2006, Peru’s tax authority, SUNAT, notified EDELNOR of several Assessment and Fine Resolutions whereby SUNAT objected to the Income Tax and General Sales Tax paid from 2000 to 2003. With regards to Income Tax, SUNAT objected to the tax loss declared. Edelnor accepted these objections in part and questioned some of them. In relation to General Sales Tax (IGV), the objections were substantially less. EDELNOR filed an appeal against these resolutions with SUNAT. In February 2009, EDELNOR was notified of administrative trial-level resolutions issued by SUNAT (First Administrative Instance), which in part upheld the company’s appeal with SUNAT. In May 2009, an appeal was filed against these resolutions with the Tax Court. In November 2012 EDELNOR was notified of the Resolution of the Tax Court that terminated the administrative instance to the contest filed against the defined minutes relative to Income Tax from 2000 to 2004, which includes the COLFONAVI (Comisión Liquidadora del Fondo Nacional de Vivienda) issue, resolution that is in part favorable for EDELNOR. Regarding COLFONAVI, although the Tax Court has not recognized as a deductible expense of the 2000 accounting period, it has recognized Edelnor’s right to depreciation, and ordered SUNAT to recalculate the depreciation. In relation to the 2004 accounting period, the court revoked the appealed IR and ordered SUNAT to resettle the Income Tax according to what was provided by RTF, taking into account the results of the records IR 2000-2001 and IR 2002-2003. EDELNOR filed with the Tax Court an appeal against the Intendancy Resolutions of SUNAT, which carries out the calculation and resettlement. The appeal is pending admission to processing. The amount involved is approximately US$ 18.67 million.

17.- On May 24, 2011, Endesa Chile was served with a lawsuit filed by 19 riparian owners along the Pirihueico Lake, seeking to declare null DGA Resolution 732, which authorized the relocation of water uptake rights for the Neltume station, from the Pirihueico Lake 900 meters downstream along Fui River. The plaintiffs seek to have this annulment annotated at the margin of the notarized instrument that memorialized DGA Resolution 732, which approved the transfer of the uptake. The plaintiffs also seek to have the recordation of said instrument struck from the waters registry, if entered, and to require the Chilean Treasury, the DGA and Endesa Chile to pay damages to the plaintiffs as a result of the challenged DGA resolution, seeking to reserve their right to indicate the type and amount of damages in subsequent legal proceeding. The claim is for an undetermined amount since the plaintiffs have requested that damages be determined in another suit, once the DGA’s administrative resolution is declared null and void. To date the discussion period is over and the discovery writ has been issued, which has been served on the plaintiffs and Endesa Chile, both of whom filed motions seeking the annulment or modification of the writ which were both rejected. The proceeding is suspended by mutual agreement by the parties, until March 9, 2013.

18.- In 1996, 45 workers filed a suit requesting reinstatement to their employment positions with Enersis’ Brazilian distribution company, Ampla. Ampla obtained a favorable ruling in 2003. The Higher Labor Court of Law (Tribunal Superior de Trabalho) acknowledged that the workers voluntary early retirement terminated the work contracts. Based on some judicial decisions that recognized that upholding these voluntary early retirement programs did not terminate the work contracts, the workers filed a “rescissory claim” before the Higher Labor Court of Law grounded on such judicial decisions. Ampla, in the course of this proceeding, is attempting to uphold the unconstitutionality of the legislative resolution of the Energy Secretary of the State of Río de Janeiro and the consequent non-existence of the stability right, regardless of whether voluntary early retirement cancels the work contract or not. Ampla filed an Amendment of Judgment alleging the expiration of the right of the plaintiffs to file a rescissory suit, which was accepted and the court determined that the re-integration of the plaintiffs in Ampla was annulled. The sum of this trial is estimated to be approximately US$ 54.09 million.

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19.- The Regional Trade Union of Endesa Chile Workers (Sindicato Regional de Trabajadores de Endesa Chile), filed a lawsuit against Endesa Chile, Endesa Eco, Central Eólica Canela S.A., Celta, Pangue, Pehuenche and San Isidro, seeking a judgment declaring that Endesa Chile must determine the “operational profitability” based on the 2011 Balance Sheet and 2011 Annual Report, registered before the Superintendence of Securities and Insurance (Superintendencia de Valores y Seguros) and published on the Web Page www.endesa.cl, which stated that its operational profitability was 15% higher in the 2011 Accounting Period and that, consequently, the maximum share of the bonus for profits regarding the 2011 Accounting Period corresponds to the workers affiliated to the plaintiff trade union. The bonus amounts to 2.15 wages (RBPM) for the adjustment that corresponds since the Group Bargaining Contracts were in force during that year, and for the second half of 2011 (current Group Bargaining Contract), 2.3 RBPM and for the first half (prior Group Bargaining Contract), 2.0 RBPM. The plaintiffs requested that Endesa Chile be required to pay them the difference between 2.15 RBPM and what was effectively paid (0.5742 RBPM), amounting to 1.5758 RBPM, plus readjustments, interests and costs. In case that the court declares that Endesa Chile’s operational profitability must be determined based on the Parent Company’s results, the plaintiffs requested the companies in which Endesa Chile’s overwhelming majority participation and lack workers whether totally or virtually, not be considered as “subsidiaries,” at least for labor purposes. For this reason, the profit sharing bonus must be calculated on the operational profitability obtained by Endesa Chile with the so-called affiliates. Consequently, Endesa Chile could have to pay the workers affiliated to the plaintiff Trade Union the difference between the RBPM associated to the operational profitability obtained in the aforementioned manner and what was effectively paid, 0.5742 RBPM, plus readjustments, interests and costs. In addition, if the court decides that Endesa Chile’s operational profitability must be determined based on its parent company’s results, without the aforementioned subsidiaries, the profit sharing bonus must be calculated based on formal and verifiable background information established by the court and not on Endesa Chile’s assertions. For the above purpose of determining specific amount corresponding to each worker for profit sharing, the value of their wages (RBPM) must be considered, which amount must be set based on credited background information and determined during the proceeding process or in the ruling compliance stage. Additionally, the plaintiffs requested that Endesa Chile in the future pay the profit sharing benefit over the same criteria determined by the court in the proceeding sentence. The parties have been called to attend preparatory hearing on February 5, 2013, at 09:10 a.m. The term to contest the lawsuit matures on January 29, 2013.

The Enersis management considers that the provisions registered in the Consolidated Financial Statements, attached hereto, adequately cover the risks resulting from litigation and other operations described in this Note, which is why it does not consider that there are additional liabilities than those specified herein.

Given the characteristics of the risks covered by these provisions, it is impossible to determine a reasonable schedule of payment dates, in case there are any.

34.4

Financial Covenants

Various of the company’s loan agreements, and those of some of its subsidiaries, include the obligation to comply with certain financial ratios, normal in contracts of this nature. There are also covenants and negative covenants requiring the monitoring of these commitments. In addition, there are restrictions in the events-of-default clauses of the agreements which require compliance.

1-. Cross default

Some of the financial debt contracts of Enersis S.A. and of Endesa Chile contain cross default clauses. The syndicated loan of Endesa Chile under New York law signed in 2008 and which expires in 2014, with an amount disbursed of US$ 200 million at the present time, makes no reference to its subsidiaries, so a cross default can only arise with respect to another own debt. In order to accelerate payment of the debt of this loan due to cross default with respect to another debt, the amount overdue of a debt must exceed US$ 50 million, or the equivalent in other currencies, and other additional conditions should be met including the expiry of grace periods (if any) and formal notification of the intention to accelerate the debt by creditors representing over 50% of the amount due under the agreement.

Regarding the bond issues of Enersis S.A. and Endesa Chile registered with the United States Securities and Exchange Commission (“SEC”), commonly called “Yankee Bonds,” a cross default can be triggered by another debt of the same company or of any of their Chilean subsidiaries, for any amount overdue provided that the principal of the debt giving rise to the cross default exceeds US$ 30 million or its equivalent in other currencies. Debt acceleration due to cross default does not occur automatically but has to be demanded by the holders of at least 25% of the bonds of a certain series of Yankee Bonds. In addition, events of bankruptcy or insolvency of foreign subsidiaries have no contractual effects on the Yankee Bonds of Enersis S.A. and Endesa Chile. The last Yankee Bond of Enersis S.A. matures in December 2026 and that of Endesa Chile in February 2097.

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The domestic bonds of Enersis S.A. and Endesa Chile state that cross default can be triggered only by the default of the issuer, and debt acceleration requires the agreement of at least 50% of the holders of the bonds of a certain series.

2-. Financial Covenants

Financial covenants are contractual commitments with respect to minimum or maximum financial ratios that the company is obliged to meet at certain periods of time (quarterly, annually, etc.). Most of the financial covenants of the Group limit the level of indebtedness and evaluate the ability to generate cash flows in order to service the companies’ debts. Various companies are also required to certify these covenants periodically. The types of covenants and their respective limits vary according to the type of debt.

The Series B2 domestic bonds of Enersis S.A. include the following financial covenants, whose definitions and calculation formulas are set out in the respective contract:

- Equity: A minimum Equity should be maintained of Ch$ 592,579 million a limit adjusted at the end of each year as established in the indenture. Equity is the sum of Equity attributable to the dominant company and Minority participations. As of December 31, 2012, the equity of Enersis S.A. was Ch$ 6,963,769 million.

- Debt Ratio: A debt ratio, being Total liabilities to Equity, should be no more than 2.24:1. Total liabilities are the sum of Total current liabilities and Total non-current liabilities, while Equity is the sum of Equity attributable to the dominant company and Minority participations. As of December 31, 2012, the ratio of total liabilities to equity of Enersis S.A. was 0.91.

- Unsecured Assets: The ratio of Unsecured assets to Unsecured total liabilities should be at least 1:1. Total Unsecured or free assets is the difference between Total assets and Total secured assets. Total unsecured or free assets consists of Total assets less the sum of Cash, Bank balances, Accounts receivable from related entities, current, Payments made in advance, current, Accounts receivable from related entities, non-current and Identifiable intangible assets, gross, while Total secured assets relates to assets pledged in guarantee. On the other hand, Unsecured total liabilities consist of the sum of Total current liabilities and Total non-current liabilities, less liabilities secured by collateral. As of December 31, 2012, this ratio was 1.78.

The Yankee Bonds are not subject to any financial covenants.

As of December 31, 2012, the most restrictive financial covenant of Enersis S.A. was the debt ratio with respect to domestic bonds Serie B2, which expires in June 2022.

The domestic bonds of Endesa Chile include the following financial covenants whose definitions and calculation formulas are established in the respective indentures:

Series H

- Consolidated Debt Ratio: A consolidated debt ratio, being Financial debt to Capitalization, should be no more than 0.64. Financial debt is the sum of Interest-bearing loans, current, Interest-bearing loans, non-current, Other financial liabilities, current, Other financial liabilities, non-current and Other obligations guaranteed by the issuer or its subsidiaries, while Capitalization is the sum of Financial liabilities, Equity attributable to the dominant company and Minority participations. As of December 31, 2012, the ratio was 0.38.

- Equity: A minimum Equity should be maintained of Ch$ 756,942 million, which limit is adjusted at the end of each year as established in the indenture. Equity is the sum of Equity attributable to the dominant company and Minority participations. As of December 31, 2012, the equity of Endesa Chile was Ch$ 2,541,242 million.

- Financial Expense Coverage: A financial expense coverage ratio should be maintained of at least 1.85. Financial expense coverage is the quotient between i) the Gross margin plus Financial income and Dividends received from associate companies, and ii) Financial expenses; both items refer to the period of four consecutive quarters months ending on the quarter being reported. In the period ended December 31, 2012, this ratio was 5.76.

- Net Asset Position with Related Companies: A Net asset position should be maintained with related companies of no more than a hundred million dollars. The Net asset position with related companies is the difference between i) the sum of Accounts receivable from related entities, current, Accounts receivable from related entities, non-current, less transactions in the ordinary course of business at less than 180 days term, short-term transactions of associates of Endesa Chile in which Enersis S.A. has no participation, and long-term transactions of associates of Endesa Chile in which Enersis S.A. has no participation, and ii) the sum of Accounts payable to related entities, current, Accounts payable to related entities, non-current, less transactions in the ordinary course of business at less than 180 days term, short-term transactions of associates of Endesa Chile in which Enersis S.A. has no participation, and long-term transactions of associates of Endesa Chile in which Enersis S.A. has no participation. As of December 31, 2012, using the exchange rate prevailing on that date, the Net asset position with related companies was a negative US$ 349.1 million.

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Series M

- Consolidated Debt Ratio: A consolidated debt ratio, being Financial debt to Capitalization, should be no more than 0.64. Financial debt is the sum of Interest-bearing loans, current, Interest-bearing loans, non-current, Other financial liabilities, current, Other financial liabilities, non-current, while Capitalization is the sum of Financial liabilities, Equity attributable to the dominant company and Minority participations. As of December 31, 2012, the debt ratio was 0.36.

- Equity: As for Series H.

- Financial Expense Coverage Ratio: As for Series H.

The rest of the debt of Endesa Chile includes other covenants like leverage and debt coverage ratios (debt/EBITDA ratio), while the Yankee Bonds are not subject to financial covenants.

In the case of Endesa Chile, the most restrictive financial covenant as of December 31, 2012 was the debt ratio, with respect to the syndicated loan under New York law which expires in June 2014.

In Peru, the debt of Edelnor only has one covenant, a debt ratio with respect to the domestic bonds which mature in May 2032 and a loan from Banco de Crédito which matures in September 2018. On the other hand, the debt of Edegel includes the following covenants: debt, leverage, interest coverage, equity to debt and debt to equity and debt coverage (debt/EBITDA) ratios. As of December 30, 2012, the most restrictive financial covenant of Edegel was the debt ratio, corresponding to the 2nd domestic bonds program which matures in January 2014.

In Brazil, the debt of Coelce includes compliance with the following covenants: interest coverage (EBITDA/financial expenses), debt repayment coverage (debt/EBITDA) and debt ratios. As of December 31, 2012, the most restrictive financial covenant of Coelce was the debt/EBITDA ratio, corresponding to the 2nd and 3rd domestic bond issues, whose final maturity is October 2018. The debt of Ampla includes the following covenants: debt payment coverage, interest coverage and short-term debt (short-term debt to EBITDA) ratios. As of December 31, 2012, the most restrictive financial covenant of Ampla was the debt payment coverage ratio, corresponding to the 5th, 6th and 7th domestic bond issues, whose final maturity is June 2019.

In Argentina, Endesa Costanera has just one covenant which is the maximum debt, corresponding to a loan from Credit Suisse International which matures in March 2013. The debt of El Chocón includes covenants of maximum debt, equity, interest coverage, debt payment coverage (debt/EBITDA) and leverage ratios. In the case of El Chocón, as of December 31, 2012, the most restrictive financial covenant was the interest coverage ratio, corresponding to loans from Deutsche Bank, Standard Bank and Itaú which mature in February 2015.

In Colombia, the debts of Codensa and Emgesa are not subject to compliance with financial covenants, a situation that also applies to the debt of the rest of the companies not mentioned in this Note.

Lastly, in most of the contracts, debt acceleration for non-compliance with these covenants does not occur automatically but is subject to certain conditions, like a cure period.

As of December 31, 2012 and December 31, 2011, neither Enersis S.A. nor Endesa Chile, nor any of their subsidiaries are in default under their financial obligations summarized here or other financial obligations whose defaults might trigger the acceleration of their financial commitments, with the sole exception of Endesa Costanera, our Argentine generation subsidiary, which has still not repaid the installment of US$ 17.6 million due under a supplier credit with Mitsubishi Corporation which was due on March 31, 2012, for which no waiver has been received. The grace period established was 180 days and expired on September 26, 2012. Endesa Costanera has not repaid the second installment of US$17 million that matured at the end of September 2012. Under the contract terms, and as the grace period of 180 days has expired, should Mitsubishi Corporation wish to accelerate the amount outstanding of this loan, it would have to notify formally ten days in advance. To date, Endesa Costanera has not received such notification from Mitsubishi Corporation and negotiations are currently proceeding to restructure the unpaid installments. Should Mitsubishi Corporation send a formal communication of debt acceleration, total loans of US$ 141 million would be payable. None of this represents a cross-default risk or other default for Enersis S.A. or Endesa Chile.

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34.5

Other information

- Our Argentine subsidiary Endesa Costanera shows a working capital deficit, pressed by the difficulties it is facing in obtaining tariff adjustments to cover the real costs of generation, leading to problems in its short-term financial equilibrium. Endesa Costanera expects to correct the present situation depending on a favorable resolution of requests made to the Argentine government. The equity risk that this company represents for the Enersis S.A. is not significant.

- On July 12, 2012, the Argentine electricity regulatory authority (Ente Nacional Regulador de la Electricidad de la República Argentina (ENRE)), by its Resolution 183/2012, informed Edesur of the appointment of a “Veedor” (a kind of inspector) for an extendable term of 45 days in order to control and verify all normal administrative actions linked to the normal provision of the electricity distribution service public utility by Edesur. On September 13, 2012 the ENRE, by Resolution 246/2012, stated that the “veedor” will be maintained for another extendable period of 45 days. On November 14, 2012 the ENRE, by Resolution 337/2012, stated that the “veedor” will be maintained for another extendable period of 45 business days. The appointment of the “veedor” does not imply the loss of control by Enersis of Edesur. Edesur considers that this appointment and its justification are inappropriate and therefore it brought proceedings against the ENRE each time the period has been extended.

35.

PERSONNEL FIGURES

Enersis personnel, including that of subsidiaries and jointly-controlled companies in the five Latin American countries where the Group is present, is distributed as follows as of December 31, 2012 and 2011:


		12-31-2012
Country	Managers and Main Executives		Professionals and Technicians		Workers and Others		Total		Average for the Period
Chile		89		2,057		316		2,462		2,451
Argentina		40		2,427		982		3,449		3,362
Brazil		34		2,368		260		2,662		2,740
Peru		20		691		159		870		841
Colombia		27		1,563		54		1,644		1,634
Total		210		9,106		1,771		11,087		11,028


		12-31-2011
Country	Managers and Main Executives		Professionals and Technicians		Workers and Others		Total		Average for the Period (*)
Chile		94		1,963		340		2,397		2,522
Argentina		43		2,401		883		3,327		3,242
Brazil		40		2,414		310		2,764		2,780
Peru		20		624		153		797		854
Colombia		27		1,517		55		1,599		1,641
Total		224		8,919		1,741		10,884		11,039

(*) Includes average staff at Cam and Synapsis up to the time they were sold. See Note 2.4.1 and Note 11.

36.

SANCTIONS

The following companies belonging to the Group have received sanctions from the administrative authorities:

1.- Endesa Chile

- During the 2011 fiscal year, the company was fined ThCh$ 662,482 by the Electricity and Fuels Superintendency (SEF) for the blackout on March 14, 2010. Endesa Chile filed an appeal against the measure with the Santiago Court of Appeals, which rejected the appeal on January 18, 2013 and upheld the fine. The timeframe for appealing against this ruling has not yet expired.

F-119

2.- Pehuenche

- On October 6, 2011, the Securities and Insurance Superintendency (Superintendencia de Valores y Seguros, SVS) issued Exempt Resolution No. 545 and applied a sanction fining the Directors of Pehuenche who participated in the approval of the Energy and Capacity agreement signed between the Company and its parent company, Empresa Nacional de Electricidad S.A. (Endesa), on November 19, 2007.

The following fines were applied:

i) The Directors who were not members of the Directors’ Committee were fined for not having verified, according to the SVS resolution, that the Energy and Capacity sales agreement signed between Empresa Eléctrica Pehuenche S.A. and its parent company Endesa on November 19, 2007 was entered into under equitable conditions normally prevailing in the market, and for having approved the Minutes of the Board meeting stating that Directors’ Committee Report had been read when only the Minutes of the Directors’ Committee meeting had actually been read. The Directors were fined 300 UF each.

ii) The Directors who were members of the company’s Directors’ Committee on the date that the aforementioned agreement was signed were fined for not having issued, in accordance with the SVS resolution, the Report referred to in that regulation. They were each fined 400 UF.

The Directors filed an appeal with the competent civil court after paying 25% of the total fine to the General Treasury of the Republic. As a consequence, the fines and their grounds are being questioned before the ordinary courts of law, which, in a summary proceeding, are studying the Directors’ claim requesting their acquittal.

On August 22, 2012, the first party, Endesa, and the second party, Inversiones Tricahue and other minority shareholders, entered into a transactional agreement in which the minority shareholders desisted from all arbitration, administrative, and criminal actions against Endesa, Pehuenche, and the Directors who were in place on November 19, 2007. In exchange, Endesa agreed to rescind the capacity and energy supply agreement of November 19, 2007 and enter into a new one under the same conditions but with prices at marginal cost; this agreement will be in force as of the date it is signed until December 31, 2021. Both parties also agreed to vote favorably on the rescission and the signing of the new agreement at the Pehuenche Extraordinary Shareholders’ Meeting. Endesa undertook to pay Pehuenche the price difference that arose from the price of the November 19, 2007 agreement, in force from January 1, 2008 to July 31, 2012, and the price difference from that paid from August 1, 2012 until the date the new capacity and energy supply agreement was signed, according to the calculation methods and conditions of the new agreement. On October 4, 2012, the Pehuenche Extraordinary Shareholders’ Meeting unanimously approved the rescission and the signing of a new contract. On October 19, the Pehuenche Board of Directors voted to pay an interim dividend for the amount it will receive from the price differences implemented by Endesa; the dividend will be paid on November 5, 2012. However, the Directors must pay the fine imposed by the SVS. The respective insurance will cover these fines, and we are in the process of declaring and paying these sanctions to the Treasury.

- During the 2011 fiscal year, the company was fined ThCh$ 288,996 by the Electricity and Fuels Superintendency (SEF) for the blackout on March 14, 2010. Pehuenche has filed an appeal against the measure with the Santiago Court of Appeals, which rejected the appeal on January 18, 2013 and upheld the fine. The timeframe for appealing against this ruling has not yet expired.

3.- Chilectra S.A.

In the fiscal year ended December 31, 2012, Chilectra S.A. received 19 fines totaling ThCh$ 1,050,663 from the Electricity and Fuels Superintendency (SEF) for different reasons in connection with power supply and facilities. Chilectra S.A. was also fined ThCh$ 3,969 by the Regional Health Ministry Office of the Metropolitan Region for failure to comply with regulations on the storage of materials. During the 2011 fiscal year, the Company was fined ThCh$ 29,529 for technical failures related to power supply. The management has filed the corresponding appeals or claim for each sanction.

4.- Edelnor S.A.A.

For the period ending December 31, 2012, Edelnor S.A.A. has been issued five fines totaling S/17,057,205 Peruvian sols (ThCh$ 3,210,500) in connection with income taxes owed for the 2007 and 2008 fiscal years. The company has filed the respective appeals.

Also, during the 2012 fiscal year, the Agency for the Supervision of Investment in Energy and Mining (Organismo Supervisor de la Inversión en Energía y Minería, OSINERG) issued 19 fines to Edelnor S.A.A. totaling S/463,645.77 Peruvian sols (ThCh$ 87,267) for failure to comply with technical and commercial quality regulations; it received 47 fines totaling S/717,000 Peruvian sols (ThCh$ 138,081) in 2011.

F-120

5.- Edesur S.A.

For the year ended December 31, 2012, Edesur S.A. received 819 fines from the Energy Regulatory Body (Ente Regulador de Energía, ENRE) totaling ThCh$ 1,326,379 (Th$ 13,591 Argentine pesos) for failure to comply with technical and commercial quality regulations. During the 2011 fiscal year, the Company received 182 fines for the same reasons totaling ThCh$ 10,075,970 (Th$ 83,526 Argentine pesos).

6.- Hidroeléctrica El Chocón S.A.

For the year ended December 31, 2012, Hidroeléctrica El Chocón was fined ThCh$ 299,511 (Th$ 3,069 Argentine pesos) by the Jurisdictional Authority of the Limay, Neuquén, and Negro River Basins (Autoridad Jurisdiccional de las Cuencas de los Ríos Limay, Neuquén Negro, AIC) for failure to comply with water extraction from its basins. The company has presented the respective appeal.

7.- Endesa Costanera S.A.

During the 2011 fiscal year, the company received two fines totaling ThCh$ 2,422 ($ 24,000 Argentine pesos) from the Energy Regulatory Body (ENRE). The company has filed the respective appeal.

8.- Ampla Energía S.A.

For the period ending December 31, 2012, the company received one fine for ThCh$ 673,664 (Th$ 2,863 Brazilian reals) from the National Electrical Energy Agency (Agencia Nacional de Energía Eléctrica, ANEEL) for power consumption metering. In 2011, it received three fines totaling ThCh$ 1,959,386 (Th$7,079 Brazilian reals) for violation of telemarketing and energy sale tariff indicators. For the period ended December 31, 2012, Ampla has also been fined ThCh$ 1,759,573 (Th$ 7,478 Brazilian reals) by the Federal Revenue Office (Secretaria de Receita Federal) for failure to meet tax obligations. The company has filed the respective appeal.

9.- Coelce

For the period ending December 31, 2012, the company received two fines totaling ThCh$ 162,122 (Th$ 689 Brazilian reals) from the National Electrical Energy Agency (ANEEL) for failure to comply with technical regulations. During the 2011 fiscal year, the company received three fines totaling ThCh$ 386,674 (Th$ 1,397 Brazilian reals) from the National Electrical Energy Agency (ANEEL) for the same reason as in 2012. It also received eight fines in 2012 totaling ThCh$ 5,387,433 (Th$ 22,937,784 reals) from the Ceará State Regulatory Agency. The company has filed the respective appeals.

10.- Edegel

During the 2012 fiscal year, the Administración Tributaria (Tax Administration, SUNAT) ordered Edegel S.A.A. to pay S/37,710,176 Peruvian sols (ThCh$ 7,097,795) for Omitted Taxes plus interest and penalties in connection with an audit of its 1999 income tax that began in January of 2006. Edegel S.A.A. has filed an administrative claim disputing the decision.

During the 2011 fiscal year. Edegel S.A.A. was notified by the Administración Tributaria (SUNAT) of resolutions determining taxes and fines regarding alleged omissions in the filing of its 2006 income tax. The contingency associated with these allegations, updated at December 31, 2011, was S/25,546,000 Peruvian sols (ThCh$ 4,919,690), including fines and interest. The company has filed an appeal, which is pending resolution by the Tax Court.

11.- The company and its Board of Directors have not received other fines from the SVS or from other administrative authorities.

37.

SUBSEQUENT EVENTS

ENERSIS

The following essential events are reported in accordance with Articles 9 and 10, second section, of Law 18,045 on the Securities Market and the provisions of that Superintendency’s General Regulation No.30.

- On January 8, 2013, the company reported that Empresa Nacional de Electricidad S.A. (Endesa Chile) has accepted the terms received from insurance adjustor Becket S.A. Liquidadores de Seguros informed in letter dated January 7, 2013 regarding the final and definitive amount to be paid for the losses sustained in the February 27, 2010 earthquake. These terms have also been accepted by all of the insurance companies.

Regarding Endesa Chile’s Bocamina 1 plant, an agreement has been reached on the insurance settlement, with US$ 85,665,673 to be paid for loss of profits and material damage (US$ 66,165,673 and US$ 19,500,000, respectively) as a result of the earthquake. Our subsidiary has received advance cash payments of US$ 42,665,673 for the loss.

F-121

Regarding Bocamina 2, also owned by Endesa Chile, the claim settlement involves US$ 112,999,528, of which US$ 2,953,306 is for material damage and US$ 110,046,222 is for loss of profits (ALOP).

As of December 31, 2012, our subsidiary Endesa Chile has recorded US$ 114,711,895 in its operating results for settlement of an insurance claim covering loss of profits. This results in a gain of US$ 55,043,356 for Enersis after taxes and non-controlling interests.

- On January 22, 2013, Enersis S.A. (Enersis) reported that, regarding the essential event reported on December 21, 2012 involving the capital increase approved at the December 20, 2012 Extraordinary Shareholders’ meeting, it has been studying the placement of shares both in Chile and in foreign markets through an ADR (as this term is defined in the Bulletin) program with the following investment banks / placement agents: J.P. Morgan, BTG Pactual / Celfin, Bank of America Merrill Lynch, Banchile, BBVA, Credit Suisse, Deutsche Bank, Goldman Sachs, HSBC, Larraín Vial, Morgan Stanley, Santander, Bank of Tokyo, Mitsubishi UFJ Securities, BNP Paribas, and Credit Agricole CIB.

Enersis S.A. will report the information required under Section II.1b) of the Bulletin as soon as it is available.

Nothing reported in this essential event constitutes an offer to sell securities in the United States of America. The securities cannot be offered or sold in the United States of America without a registration or a registration exemption. Enersis plans to register securities for public sale in the United States of America in connection with its announced capital increase.

Any public offer of securities in the United States of America will be made through a prospectus that will be available from the issuer or the depository of the securities for sale and that will contain detailed information on Enersis, its management, and its financial statements.

On January 29, 2013, our subsidiary Endesa Chile reported that, in the international arbitration procedure filed by our company with the International Chamber of Commerce of Paris (ICC) in October 2012 due to the differences between the parties to the Turnkey Construction Agreement for the Bocamina II thermoelectric plant owned by Endesa Chile, Endesa has been notified by the Technical Office of the Paris International Chamber of Commerce that the members of the SES-TECNIMONT Consortium have proceeded to answer Endesa Chile’s arbitration request separately with their claims and, at the same time, have filed a countersuit against Endesa Chile for US$ 1,294 million in the case of Tecnimont and US$ 15 million in the case of SES.

Endesa Chile considers that there are no grounds for the countersuits, so our company will defend its position in this arbitration suit with the conviction that the law and the facts in this dispute are on its side, and have justified its collection on the bank guarantee bonds due to the Consortium’s serious breaches of contract.

Considering the above, and given the unfounded claims of the countersuits, the company does not anticipate any adverse financial effects on its assets, liabilities, or results at this time.

No other subsequent events of significance have occurred between January 1, 2013 and the date these financial statements were issued.

38.

ENVIRONMENT

Environmental expenses as of December 31, 2012, 2011, and 2010 are as follows:


Company Incurring the Cost	Project	12-31-2012 ThCh$	12-31-2011 ThCh$	12-31-2010 ThCh$
Endesa Chile S.A.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste at hydroelectric power stations (HPS) and thermoelectric power stations	2,298,344	2,104,631	2,460,261
Gas Atacama S.A.	Environmental monitoring (air quality, marine monitoring, etc.)	41,802	72,711	72,984
Centrales Hidroeléctricas de Aysen S.A.	Expenses in education and tourism	124,990	455,617	294,327
Chinango	Air and climate protection, waste water management, soil and water recovery, noise and vibration reduction, biodiversity and landscape protection	451,030	211,544	-
Edegel S.A.A.	Environmental monitoring, waste management, mitigation and restoration	464,295	336,435	444,983
Codensa	Environmental management of PCB transformers.	-	71,667	69,820
Chilectra	Weed removal on substation premises, tree pruning in AT, garden maintenance, oil-contaminated solids	1,324,061	1,681,800	4,344
Ampla Energia	Environmental license and environmental management equipment	-	-	17,377
Edesur S.A.	Final disposal of waste and contaminants	-	56,185	10,287
Compañía de Transmisión del Mercosur S.A.	ISO 14,001 audit and ENRE 57/2003 Resolution (Public Safety), environmental monitoring, and environmental standards update	-	15,100	13,412
Transportadora de Energía S.A.	ISO 14,001 audit and ENRE 57/2003 Resolution (Public Safety), environmental monitoring, and environmental standards update	-	16,387	14,714

Total		4,704,522	5,022,077	3,402,509

F-122

39.

SUMMARIZED FINANCIAL INFORMATION ON PRINCIPAL SUBSIDIARIES AND JOINT VENTURES

As of December 31, 2012 and 2011, the summarized financial information of our principal subsidiaries and joint ventures under IFRS is as follows:


	12-31-2012
	Type of Financial Statements	Current Assets ThCh$		Non-current Assets ThCh$		Total Assets ThCh$		Current Liabilities ThCh$		Non-current Liabilities ThCh$		Total Liabilities ThCh$		Revenues ThCh$		Costs ThCh$		Profit (Loss) ThCh$
Chilectra S.A.	consolidated		164,345,697		1,139,112,814		1,303,458,511		(195,903,831)		(70,857,008)		(266,760,839)		974,543,004		(798,781,836)		175,761,169
Inmobiliaria Manso de Velasco Ltda.	consolidated		33,956,699		34,725,275		68,681,974		(4,487,954)		(473,280)		(4,961,234)		12,042,940		565,251		12,608,192
ICT Servicios Informáticos Ltda.	separate		4,302,210		327,443		4,629,653		(2,560,716)		(686,662)		(3,247,378)		6,158,048		(5,711,991)		446,057
Inversiones Distrilima S.A.	separate		14,081,778		45,150,539		59,232,317		(1,690)		-		(1,690)		-		13,767,559		13,767,559
Empresa de Distribución Eléctrica de Lima Norte S.A.A.	separate		69,076,427		456,528,436		525,604,863		(121,208,497)		(202,239,406)		(323,447,903)		375,147,825		(335,221,434)		39,926,390
Empresa Nacional de Electricidad S.A.	separate		629,902,712		3,231,692,665		3,861,595,377		(658,103,026)		(791,579,065)		(1,449,682,091)		1,140,273,857		(948,756,853)		191,517,004
Endesa Eco S.A.	separate		96,858,959		69,458,787		166,317,746		(146,333,479)		(2,483,081)		(148,816,560)		8,715,658		(15,069,072)		(6,353,414)
Empresa Eléctrica Pehuenche S.A.	separate		53,256,062		226,690,237		279,946,299		(67,804,287)		(44,094,780)		(111,899,067)		374,992,088		(117,294,279)		257,697,809
Compañía Eléctrica San Isidro S.A.	separate		51,106,086		201,289,793		252,395,879		(106,039,552)		(21,730,290)		(127,769,842)		278,773,184		(223,658,845)		55,114,339
Empresa Eléctrica Pangue S.A.	separate		-		-		-		-		-		-		21,743,445		(10,100,577)		11,642,868
Compañía Eléctrica Tarapacá S.A.	separate		18,675,677		72,323,119		90,998,796		(10,274,500)		(4,390,710)		(14,665,210)		36,327,247		(51,556,757)		(15,229,510)
Inversiones Endesa Norte S.A.	separate		-		-		-		-		-		-		563,298		(350,866)		212,432
Inversiones Gas Atacama Holding Ltda.	separate		109,901,311		280,273,935		390,175,246		(48,808,533)		(42,927,589)		(91,736,122)		119,376,455		(82,726,987)		36,649,468
Soc. Concesionaria Túnel El Melón S.A.	separate		5,671,843		14,638,326		20,310,169		(2,924,404)		(9,068,755)		(11,993,159)		9,540,642		(1,224,447)		8,316,195
Endesa Argentina S.A.	separate		13,909,791		30,612,330		44,522,121		(456,855)		(4,479,929)		(4,936,784)		-		3,123,830		3,123,830
Endesa Costanera S.A.	separate		26,248,574		116,505,733		142,754,307		(195,463,171)		(10,460,347)		(205,923,518)		291,930,406		(340,775,547)		(48,845,141)
Hidroeléctrica El Chocón S.A.	separate		15,500,507		148,052,530		163,553,037		(29,439,486)		(48,058,461)		(77,497,947)		49,192,999		(34,794,050)		14,398,948
Emgesa S.A. E.S.P.	separate		285,737,507		1,558,061,492		1,843,798,999		(179,589,763)		(757,392,282)		(936,982,045)		579,490,648		(378,229,618)		201,261,030
Generandes Peru S.A.	separate		190,469		202,696,962		202,887,431		(8,235)		-		(8,235)		-		18,720,477		18,720,477
Edegel S.A.A.	separate		73,195,465		686,321,901		759,517,366		(71,852,384)		(241,375,405)		(313,227,789)		248,227,203		(202,144,376)		46,082,826
Chinango S.A.C.	separate		6,997,326		107,354,750		114,352,076		(9,156,459)		(40,761,605)		(49,918,064)		30,172,751		(18,065,792)		12,106,959
Centrales Hidroeléctricas de Aysén S.A.	separate		10,081,574		127,061,491		137,143,065		(5,728,373)		(248,465)		(5,976,838)		-		(1,140,074)		(1,140,074)
Endesa Brasil S.A.	separate		286,665,587		904,628,344		1,191,293,931		(8,533,833)		(123,494)		(8,657,327)		-		186,136,751		186,136,751
Central Generadora Termoeléctrica Fortaleza S.A.	separate		64,532,319		134,844,881		199,377,200		(29,555,112)		(27,185,680)		(56,740,792)		139,185,606		(103,146,050)		36,039,556
Centrais Elétricas Cachoeira Dourada S.A.	separate		97,557,008		103,199,005		200,756,013		(14,682,311)		(2,283,384)		(16,965,695)		155,195,046		(47,917,978)		107,277,068
Companhia de Interconexao Energética S.A.	separate		26,050,134		246,005,938		272,056,072		(123,971,364)		(7,980,532)		(131,951,896)		67,804,297		(48,586,909)		19,217,388
Compañía de Transmisión del Mercosur S.A.	separate		16,674,370		3,631,634		20,306,004		(4,285,854)		(15,150,911)		(19,436,765)		2,469,289		(3,712,947)		(1,243,657)
Compañía Energética Do Ceará S.A.	separate		204,298,160		670,549,135		874,847,295		(163,916,127)		(297,771,151)		(461,687,278)		801,801,416		(701,107,852)		100,693,564
EN-Brasil Comercio e Servicios S.A.	separate		3,113,907		173,146		3,287,053		(1,384,682)		-		(1,384,682)		5,800,382		(4,271,001)		1,529,381
Ampla Energía E Servicios S.A.	separate		203,568,734		1,031,003,478		1,234,572,212		(216,946,648)		(503,653,846)		(720,600,494)		1,066,613,813		(949,270,631)		117,343,182
Ampla Investimentos E Servicios S.A.	separate		1,901,905		84,277,315		86,179,220		(39,947,575)		-		(39,947,575)		-		7,785,179		7,785,179
Compañía Distribuidora y Comercializadora de Energía S.A.	separate		251,980,222		941,687,103		1,193,667,325		(279,593,196)		(311,739,451)		(591,332,647)		818,749,893		(676,445,496)		142,304,397
Inversora Codensa S.A.	separate		925		77		1,002		(11)		-		(11)		-		(141)		(141)
Empresa de Energía de Cundinamarca S.A.	separate		23,345,306		108,830,580		132,175,886		(32,149,721)		(37,487,168)		(69,636,889)		75,998,697		(69,883,980)		6,114,717
Empresa Distribuidora Sur S.A.	separate		77,060,244		247,583,455		324,643,699		(376,427,291)		(17,990,925)		(394,418,216)		308,885,087		(389,691,387)		(80,806,299)


	12-31-2011
	Type of Financial Statements	Current Assets ThCh$		Non-current Assets ThCh$		Total Assets ThCh$		Current Liabilities ThCh$		Non-current Liabilities ThCh$		Total Liabilities ThCh$		Revenues ThCh$		Costs ThCh$		Profit (Loss) ThCh$
Chilectra S.A.	consolidated		193,667,154		1,116,514,950		1,310,182,104		(196,759,945)		(52,473,555)		(249,233,500)		1,035,360,191		(924,569,246)		110,790,945
Synapsis Soluciones y Servicios IT Ltda.	consolidated		-		-		-		-		-		-		6,690,708		(6,561,185)		129,523
Inmobiliaria Manso de Velasco Ltda.	consolidated		30,451,690		36,347,961		66,799,651		(3,801,501)		(675,754)		(4,477,255)		7,741,781		(1,479,399)		6,262,382
Compañía Americana de Multiservicios de Chile S.A.	consolidated		-		-		-		-		-		-		15,582,078		(16,890,062)		(1,307,984)
ICT Servicios Informáticos Ltda.	separate		3,386,984		296,193		3,683,177		(2,119,237)		(557,313)		(2,676,550)		5,897,820		(5,282,766)		615,054
Inversiones Distrilima S.A.	separate		73,612		53,558,686		53,632,298		(8,288)		-		(8,288)		12,106,048		(4,386)		12,101,662
Empresa de Distribución Eléctrica de Lima Norte S.A.A.	separate		73,237,435		434,005,821		507,243,256		(103,696,328)		(210,609,245)		(314,305,573)		311,980,876		(270,687,421)		41,293,455
Empresa Nacional de Electricidad S.A.	separate		723,937,172		3,238,686,083		3,962,623,255		(488,951,209)		(1,087,287,205)		(1,576,238,414)		1,184,084,739		(812,433,884)		371,650,855
Endesa Eco S.A.	separate		5,437,267		135,146,612		140,583,879		(139,297,158)		(8,360,757)		(147,657,915)		14,315,105		(11,047,198)		3,267,907
Empresa Eléctrica Pehuenche S.A.	separate		56,656,641		234,597,856		291,254,497		(77,321,477)		(39,046,758)		(116,368,235)		195,003,413		(78,664,231)		116,339,182
Compañía Eléctrica San Isidro S.A.	separate		68,408,746		77,242,199		145,650,945		(71,972,413)		(9,267,849)		(81,240,262)		243,562,829		(199,292,302)		44,270,527
Empresa Eléctrica Pangue S.A.	separate		34,480,062		131,950,788		166,430,850		(44,091,140)		(13,223,971)		(57,315,111)		119,050,275		(40,689,183)		78,361,092
Compañía Eléctrica Tarapacá S.A.	separate		33,507,950		78,813,461		112,321,411		(15,031,457)		(5,726,043)		(20,757,500)		39,522,009		(38,375,668)		1,146,341
Inversiones Endesa Norte S.A.	separate		41		25,157,716		25,157,757		(3,641,034)		-		(3,641,034)		-		(270,529)		(270,529)
Inversiones Gasatacama Holding Ltda.	separate		93,103,849		314,752,349		407,856,198		(77,452,970)		(45,808,413)		(123,261,383)		260,889,567		(225,125,890)		35,763,678
Soc. Concesionaria Túnel El Melón S.A.	separate		29,481,896		15,071,789		44,553,685		(5,430,649)		(11,437,055)		(16,867,704)		7,687,068		(2,664,769)		5,022,299
Endesa Argentina S.A.	separate		8,573,370		34,592,709		43,166,079		(103,684)		-		(103,684)		-		453,345		453,345
Endesa Costanera S.A.	separate		58,093,676		141,156,445		199,250,121		(160,504,466)		(61,581,301)		(222,085,767)		341,636,333		(364,229,923)		(22,593,590)
Hidroeléctrica El Chocón S.A.	separate		27,754,942		161,753,755		189,508,697		(24,739,392)		(69,116,012)		(93,855,404)		48,326,998		(36,168,754)		12,158,244
Emgesa S.A. E.S.P.	separate		239,044,005		1,393,219,292		1,632,263,297		(220,413,976)		(530,859,723)		(751,273,699)		496,479,981		(368,041,227)		128,438,754
Generandes Peru S.A.	separate		162,255		208,237,040		208,399,295		(9,633)		-		(9,633)		22,317,674		(180,671)		22,137,003
Edegel S.A.A.	separate		70,142,623		709,616,464		779,759,087		(60,257,964)		(275,273,113)		(335,531,077)		214,815,328		(140,762,791)		74,052,537
Chinango S.A.C.	separate		11,140,497		112,163,451		123,303,948		(22,972,028)		(42,065,340)		(65,037,368)		25,943,033		(17,770,892)		8,172,141
Centrales Hidroeléctricas de Aysén S.A.	separate		10,250,367		115,878,802		126,129,169		(7,348,428)		(1,035,256)		(8,383,684)		-		(4,664,851)		(4,664,851)
Endesa Brasil S.A.	separate		144,245,706		1,071,816,109		1,216,061,815		(5,924,851)		(2,225)		(5,927,076)		160,755,284		10,670,289		171,425,573
Central Generadora Termoeléctrica Fortaleza S.A.	separate		85,453,417		162,710,126		248,163,543		(40,948,473)		(38,033,756)		(78,982,229)		127,130,032		(86,764,813)		40,365,219
Centrais Elétricas Cachoeira Dourada S.A.	separate		118,123,679		144,987,597		263,111,276		(29,508,803)		(4,697,541)		(34,206,344)		126,646,148		(12,834,467)		113,811,681
Companhia de Interconexao Energética S.A.	separate		25,533,963		292,499,911		318,033,874		(151,994,548)		(16,143,887)		(168,138,435)		54,757,129		(18,519,083)		36,238,046
Compañía de Transmisión del Mercosur S.A.	separate		18,236,701		3,922,642		22,159,343		(3,751,001)		(15,927,509)		(19,678,510)		2,682,140		(2,906,410)		(224,270)
Compañía Energética Do Ceará S.A.	separate		202,961,217		773,140,433		976,101,650		(194,185,629)		(311,700,107)		(505,885,736)		805,668,597		(669,295,646)		136,372,951
EN-Brasil Comercio e Servicios S.A.	separate		2,449,053		115,999		2,565,052		(1,071,810)		(38,388)		(1,110,198)		5,839,550		(4,878,723)		960,827
Ampla Energía E Servicios S.A.	separate		215,407,325		1,102,615,089		1,318,022,414		(293,476,867)		(548,590,886)		(842,067,753)		979,024,498		(909,619,067)		69,405,431
Ampla Investimentos E Servicios S.A.	separate		1,507,987		138,395,284		139,903,271		(51,994,249)		-		(51,994,249)		-		16,979,113		16,979,113
Compañía Distribuidora y Comercializadora de Energía S.A.	separate		233,090,499		934,300,085		1,167,390,584		(294,852,363)		(379,922,653)		(674,775,016)		751,734,951		(663,876,013)		87,858,938
Inversora Codensa S.A.	separate		1,076		76		1,152		(35)		-		(35)		-		(45)		(45)
Empresa de Enería de Cundinamarca S.A.	separate		19,310,230		95,221,154		114,531,384		(21,874,858)		(35,202,438)		(57,077,296)		67,832,508		(61,248,745)		6,583,763
Empresa Distribuidora Sur S.A.	separate		86,197,848		270,721,415		356,919,263		(311,415,979)		(40,591,590)		(352,007,569)		269,794,850		(427,202,383)		(157,407,532)

F-123

APPENDIX 1 ENERSIS GROUP COMPANIES

This appendix is part of Note 2.4, “Subsidiaries and jointly-controlled entities.”

It presents the Group’s ownership interest in each company.


Taxpayer ID No. (RUT)	Company	Currency	Ownership Interest at 12-31-2012			Ownership Interest at 12-31-2011			Relationship	Country	Activity
Taxpayer ID No. (RUT)	(In alphabetical order)	Currency	Direct	Indirect	Total	Direct	Indirect	Total	Relationship	Country	Activity

96,773,290-7	Aguas Santiago Poniente S.A.	Chilean peso	0.00%	78.88%	78.88%	0.00%	78.88%	78.88%	Subsidiary	Chile	Sanitation services
Foreign	Ampla Energía E Serviços S.A.	Brazilian real	13.68%	78.25%	91.93%	13.68%	78.25%	91.93%	Subsidiary	Brazil	Electric energy production, transportation, and distribution
Foreign	Ampla Investimentos E Serviços S.A.	Brazilian real	13.68%	78.25%	91.93%	13.68%	78.25%	91.93%	Subsidiary	Brazil	Electric energy production, transmission, transformation, distribution, and sales
Foreign	Atacama Finance Co	U.S. dollar	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Cayman Islands	Portfolio company
Foreign	Compañía Americana de Multiservicios de Brasil Ltda.	Brazilian real	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	Subsidiary	Brazil	Purchase and sale of electricity-related products
Foreign	Centrais Elétricas Cachoeira Dourada S.A.	Brazilian real	0.00%	99.61%	99.61%	0.00%	99.61%	99.61%	Subsidiary	Brazil	Generation and sale of electricity
76,003,204-2	Central Eólica Canela S.A.	Chilean peso	0.00%	75.00%	75.00%	0.00%	75.00%	75.00%	Subsidiary	Chile	Promotion and development of renewable energy projects
Foreign	Central Geradora Termeléctrica Fortaleza S.A.	Brazilian real	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Brazil	Development of a thermoelectric project
76,652,400-1	Centrales Hidroeléctricas De Aysén S.A.	Chilean peso	0.00%	51.00%	51.00%	0.00%	51.00%	51.00%	Joint control	Chile	Development and running of a hydroelectric project
Foreign	Central Vuelta Obligado S.A.	Argentine peso	0.00%	34.50%	34.50%	0.00%	34.50%	34.50%	Joint control	Argentina	Electricity generation and sales
99,573,910-0	Chilectra Inversud S.A.	Chilean peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Chile	Portfolio company
96,800,570-7	Chilectra S.A.	Chilean peso	99.08%	0.01%	99.09%	99.08%	0.01%	99.09%	Subsidiary	Chile	Participation in companies of any nature
Foreign	Chinango S.A.C.	Peruvian sol	0.00%	80.00%	80.00%	0.00%	80.00%	80.00%	Subsidiary	Peru	Electric energy generation, sales, and distribution
Foreign	Companhia de Interconexao Energética S.A.	Brazilian real	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Brazil	Electric energy production, transportation, and distribution
Foreign	Compañía de Transmisión del Mercosur S.A.	Argentine peso	0.00%	99.99%	99.99%	0.00%	99.99%	99.99%	Subsidiary	Argentina	Electric energy production, transportation, and distribution
Foreign	Compañía Distribuidora y Comercializadora de Energía S.A.	Colombian peso	12.47%	9.35%	21.82%	12.47%	9.35%	21.82%	Subsidiary	Colombia	Electric energy distribution and sales

F-124


Taxpayer ID No. (RUT)	Company	Currency	Ownership Interest at 12-31-2012			Ownership Interest at 12-31-2011			Relationship	Country	Activity
Taxpayer ID No. (RUT)	(In alphabetical order)	Currency	Direct	Indirect	Total	Direct	Indirect	Total	Relationship	Country	Activity

96,783,220-0	Compañía Eléctrica San Isidro S.A. (1)	Chilean peso	0.00%	95.61%	95.61%	0.00%	100.00%	100.00%	Subsidiary	Chile	Complete electric energy cycle
96,770,940-9	Compañía Eléctrica Tarapacá S.A.	Chilean peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Chile	Complete electric energy cycle
Foreign	Compañía Energética Do Ceará S.A.	Brazilian real	0.00%	58.87%	58.87%	0.00%	58.87%	58.87%	Subsidiary	Brazil	Complete electric energy cycle
77,625,850-4	Consorcio Ara- Ingendesa Ltda.	Chilean peso	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Chile	Engineering services
76,738,990-6	Consorcio Ara- Ingendesa Sener Ltda.	Chilean peso	0.00%	33.33%	33.33%	0.00%	33.33%	33.33%	Associate	Chile	Execution and compliance of the Maipu Line Basic Engineering Contract
77,573,910-K	Consorcio Ingendesa Minimetal Ltda.	Chilean peso	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Chile	Engineering services
96,764,840-K	Constructora y Proyectos Los Maitenes S.A.	Chilean peso	0.00%	55.00%	55.00%	0.00%	55.00%	55.00%	Subsidiary	Chile	Construction and facilities
Foreign	Distribuidora Eléctrica de Cundinamarca S.A.	Colombian peso	0.00%	49.00%	49.00%	0.00%	49.00%	49.00%	Joint control	Colombia	Electricity distribution and sales
Foreign	Distrilec Inversora S.A.	Argentine peso	27.19%	24.31%	51.50%	27.19%	24.31%	51.50%	Subsidiary	Argentina	Portfolio company
Foreign	Edegel S.A.A	Peruvian sol	0.00%	83.60%	83.60%	0.00%	83.60%	83.60%	Subsidiary	Peru	Electric energy generation, sales, and distribution
Foreign	Emgesa S.A. E.S.P.	Colombian peso	0.00%	26.87%	26.87%	0.00%	26.87%	26.87%	Subsidiary	Colombia	Electric energy generation
Foreign	Emgesa Panama S.A.	U.S. dollar	0.00%	26.87%	26.87%	0.00%	0.00%	0.00%	Subsidiary	Panama	Purchase/sale of electric energy
Foreign	Empresa de Distribución Eléctrica de Lima Norte S.A.A	Peruvian sol	35.02%	30.15%	65.17%	35.02%	30.15%	65.17%	Subsidiary	Peru	Electric energy distribution and sales
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombian peso	0.00%	49.00%	49.00%	0.00%	49.00%	49.00%	Joint control	Colombia	Electric energy distribution and sales
96,588,800-4	Empresa de Ingeniería Ingendesa S.A. (2)	Chilean peso	0.00%	0.00%	0.00%	0.00%	100.00%	100.00%	Subsidiary	Chile	Engineering services
Foreign	Empresa Distribuidora Sur S.A.	Argentine peso	16.02%	77.21%	93.23%	16.02%	77.21%	93.23%	Subsidiary	Argentina	Electric energy distribution and sales
96,783,910-8	Empresa Eléctrica de Colina Ltda.	Chilean peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Chile	Complete energy cycle and related supplies
96,589,170-6	Empresa Eléctrica Pangue S.A. (1)	Chilean peso	0.00%	0.00%	0.00%	0.00%	94.99%	94.99%	Subsidiary	Chile	Complete electric energy cycle
96,504,980-0	Empresa Eléctrica Pehuenche S.A.	Chilean peso	0.00%	92.65%	92.65%	0.00%	92.65%	92.65%	Subsidiary	Chile	Complete electric energy cycle
91,081,000-6	Empresa Nacional de Electricidad S.A	Chilean peso	59.98%	0.00%	59.98%	59.98%	0.00%	59.98%	Subsidiary	Chile	Complete electric energy cycle
Foreign	Endesa Argentina S.A.	Argentine peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Argentina	Portfolio company
Foreign	Endesa Brasil S.A.	Brazilian real	22.06%	49.46%	71.52%	22.06%	49.46%	71.52%	Subsidiary	Brazil	Portfolio company
Foreign	Endesa Costanera S.A.	Argentine peso	0.00%	69.76%	69.76%	0.00%	69.76%	69.76%	Subsidiary	Argentina	Electricity generation and sales

F-125


Taxpayer ID No. (RUT)	Company	Currency	Ownership Interest at 12-31-2012			Ownership Interest at 12-31-2011			Relationship	Country	Activity
Taxpayer ID No. (RUT)	(In alphabetical order)	Currency	Direct	Indirect	Total	Direct	Indirect	Total	Relationship	Country	Activity

96,827,970-K	Endesa Eco S.A. (3)	Chilean peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Chile	Renewable energy projects
96,526,450-7	Endesa Inversiones Generales S.A. (2)	Chilean peso	0.00%	0.00%	0.00%	0.00%	100.00%	100.00%	Subsidiary	Chile	Portfolio company
Foreign	Energex Co.	U.S. dollar	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Cayman Islands	Portfolio company
Foreign	EN-Brasil Comercio e Servicos S.A.	Brazilian real	0.00%	99.99%	99.99%	0.00%	99.99%	99.99%	Associate	Brazil	Portfolio company
Foreign	Eólica Fanzenda Nova-Geracao e Comercializacao de Energía S.A.	Brazilian real	0.00%	99.95%	99.95%	0.00%	99.95%	99.95%	Associate	Brazil	Promotion and development of renewable energy projects
96,830,980-3	Gas Atacama S.A.	U.S. dollar	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Chile	Administration and management of companies
Foreign	Gasoducto Atacama Argentina S.A.	U.S. dollar	0.00%	49.99%	49.99%	0.00%	49.99%	49.99%	Joint control	Chile	Transportation of natural gas
78,882,820-9	Gasoducto Atacama Chile S.A.	U.S. dollar	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Chile	Transportation of natural gas
77,032,280-4	Gasoducto Taltal Ltda.	Chilean peso	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Chile	Transportation of natural gas
Foreign	Generandes Peru S.A.	Peruvian sol	0.00%	61.00%	61.00%	0.00%	61.00%	61.00%	Subsidiary	Peru	Portfolio company
76,041,891-9	Hidroaysén Transmisión S.A.	Chilean peso	0.00%	51.00%	51.00%	0.00%	51.00%	51.00%	Joint control	Chile	Development of electricity transmission systems
Foreign	Hidroeléctrica El Chocón S.A.	Argentine peso	0.00%	67.67%	67.67%	0.00%	67.67%	67.67%	Subsidiary	Argentina	Electric energy production and sales
Foreign	Hidroinvest S.A.	Argentine peso	0.00%	96.09%	96.09%	0.00%	96.09%	96.09%	Subsidiary	Argentina	Portfolio company
In process	ICT Servicios Informáticos Ltda.	Chilean peso	99.00%	1.00%	100.00%	99.00%	1.00%	100.00%	Subsidiary	Chile	Information and technology services
Foreign	Ingendesa do Brasil Ltda.	Brazilian real	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Brazil	Project engineering consulting
79,913,810-7	Inmobiliaria Manso de Velasco Ltda.	Chilean peso	99.99%	0.00%	99.99%	99.99%	0.00%	99.99%	Subsidiary	Chile	Construction and works
Foreign	Inversiones Distrilima S.A.	Peruvian sol	34.99%	15.38%	50.37%	34.99%	15.38%	50.37%	Subsidiary	Peru	Portfolio company
96,887,060-2	Inversiones Endesa Norte S.A. (3)	Chilean peso	0.00%	0.00%	0.00%	0.00%	100.00%	100.00%	Subsidiary	Chile	Investment in energy projects in northern Chile
76,014,570-K	Inversiones Gas Atacama Holding Ltda.	U.S. dollar	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Chile	Natural gas transportation

F-126


Taxpayer ID No. (RUT)	Company	Currency	Ownership Interest at 12-31-2012			Ownership Interest at 12-31-2011			Relationship	Country	Activity
Taxpayer ID No. (RUT)	(In alphabetical order)	Currency	Direct	Indirect	Total	Direct	Indirect	Total	Relationship	Country	Activity

Foreign	Inversora Codensa S.A.S.	Colombian peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Colombia	Investment in domestic public energy services activities
Foreign	Investluz S.A.	Brazilian real	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Brazil	Portfolio company
96,800,460-3	Luz Andes Ltda.	Chilean peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Chile	Energy and fuel transportation, distribution, and sales
96,905,700-K	Progas S.A.	Chilean peso	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Chile	Gas distribution
77,047,280-6	Sociedad Agrícola de Cameros Ltda.	Chilean peso	0.00%	57.50%	57.50%	0.00%	57.50%	57.50%	Subsidiary	Chile	Financial investments
78,970,360-4	Sociedad Agrícola e Inmobiliaria Pastos Verdes Ltda.	Chilean peso	0.00%	0.00%	0.00%	0.00%	55.00%	55.00%	Subsidiary	Chile	Financial investments
96,671,360-7	Sociedad Concesionaria Túnel El Melón S.A.	Chilean peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Chile	Execution, construction, and operation of the El Melón tunnel
79,197,570-6	Sociedad Consorcio Ingendesa-Ara Limitada	Chilean peso	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Santiago, Chile	Engineering services
Foreign	Sociedad Portuaria Central Cartagena S.A.	Colombian peso	0.00%	99.85%	99.85%	0.00%	99.85%	99.85%	Associate	Colombia	Port administration
Foreign	Southern Cone Power Argentina S.A.	Argentine peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Argentina	Portfolio company
Foreign	Termoeléctrica José de San Martín S.A.	Argentine peso	0.00%	20.86%	20.86%	0.00%	20.86%	20.86%	Associate	Argentina	Construction and operation of a combined cycle plant
Foreign	Termoeléctrica Manuel Belgrano S.A.	Argentine peso	0.00%	20.86%	20.86%	0.00%	20.86%	20.86%	Associate	Argentina	Electric energy production, transportation, and distribution
77,017,930-0	Transmisora Eléctrica de Quillota Ltda.	Chilean peso	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Joint control	Chile	Electric energy transportation and distribution
Foreign	Transportadora de Energía S.A.	Argentine peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Argentina	Electric energy production, transportation, and distribution

(1)

On May 2, 2012, Empresa Eléctrica Pangue S.A. was merged with Compañía Eléctrica San Isidro S.A.; the latter is the company which legally continues to exist.

(2)

On May 2, 2012, Empresa de Ingeniería Ingendesa S.A. and Endesa Inversiones Generales S.A. were merged with Inversiones Endesa Norte S.A.; the latter is the company which legally continues to exist.

(3)

On July 1, 2012, Inversiones Endesa Norte S.A. was merged with Endesa Eco S.A.; the latter is the company which legally continues to exist.

F-127

APPENDIX 2 CHANGES IN THE SCOPE OF CONSOLIDATION

This appendix is part of Note 2.4.1, “Changes in the scope of consolidation.”

Incorporation into the scope of consolidation during the 2012 and 2011 periods

% Ownership Interest

Company

at December 31, 2012

at December 31, 2011

Direct

Indirect

Total

Consolidation Method

Direct

Indirect

Total

Consolidation Method

Central Vuelta Obligado S.A.

0.00%

34.5%

0.00%

34.50%

Joint control

There were no companies excluded from the scope of consolidation during the 2012 and 2011 fiscal years.

APPENDIX 3 ASSOCIATED COMPANIES

This appendix is part of Note 3.h, “Investments in associates accounted for using the equity method.”


Taxpayer ID	Sociedad	Currency	Ownership Interest at 12-31-2012			Ownership Interest at 12-31-2011			Country	Activity
No. (RUT)	(In alphabetical order)	Currency	Direct	Indirect	Total	Direct	Indirect	Total	Country	Activity

96,806,130-5	Electrogas S.A	U.S. dollar	42.50%	0.00%	42.50%	42.50%	0.00%	42.50%	Chile	Portfolio company
Foreign	Endesa Cemsa S.A.	Argentine peso	0.00%	45.00%	45.00%	0.00%	45.00%	45.00%	Argentina	Electric energy wholesaler
Foreign	Endesa Market Place	U.S. dollar	0.00%	0.00%	0.00%	15.00%	0.00%	15.00%	Spain	B2B (New technologies)
76,418,940-K	GNL Chile.S.A.	Chilean peso	0.00%	33.33%	33.33%	0.00%	33.33%	33.33%	Chile	Promotion of liquefied gas supply project
76,788,080-4	GNL Quintero S.A.	U.S. dollar	0.00%	20.00%	20.00%	0.00%	20.00%	20.00%	Chile	Development, design, and supply of a liquid natural gas regasifying terminal
Foreign	Sacme S.A.	U.S. dollar	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Argentina	Electric system supervision and control

F-128

APPENDIX 4 ADDITIONAL INFORMATION ON FINANCIAL DEBT

This appendix is parte of Note 18, “Other financial liabilities.”

The following tables present the contractual undiscounted cash flows by type of financial debt:

a) Bank borrowings

Summary of bank loans by currency and maturity


					Current						Non-current								Current						Non-current
					Maturity						Maturity						Total Non-		Maturity						Maturity						Total Non-
Country	Currency	Country		One to Three Months ThCh$		Three to Twelve Months ThCh$		Total Current at 12-31-2012 ThCh$		One to Three Years ThCh$		Three to Five Years ThCh$		More than Five Years ThCh$		current at 12-31-2012 ThCh$		One to Three Months ThCh$		Three to Twelve Months ThCh$		Total Current at 12-31-2011 ThCh$		One to Three Years ThCh$		Three to Five Years ThCh$		More than Five Years ThCh$		current at 12-31-2011 ThCh$

Chile	US$		1.76%		818,386		2,531,449		3,349,835		98,982,459		-		-		98,982,459		906,389		3,359,497		4,265,886		109,631,899		876,746		-		110,508,645
Chile	Ch$		4.90%		371		-		371		-		-		-		-		-		-		-		-		-		-		-
Peru	US$		3.49%		2,214,895		1,865,048		4,079,943		14,173,501		27,830,814		12,109,598		54,113,913		2,810,297		10,519,166		13,329,463		7,864,024		25,087,748		26,158,087		59,109,859
Peru	Sol		5.50%		336,866		1,010,593		1,347,459		2,694,912		9,719,488		15,531,401		27,945,801		431,794		2,987,507		3,419,301		3,362,985		-		38,373,491		41,736,476
Argentina	US$		8.91%		6,845,061		5,093,612		11,938,673		7,836,715		-		-		7,836,715		2,662,019		9,436,481		12,098,500		17,142,594		1,612,063		-		18,754,657
Argentina	Ar$		20.96%		29,510,090		30,335,750		59,845,840		11,637,995		-		-		11,637,995		37,689,501		28,405,542		66,095,043		47,915,942		2,458,440		-		50,374,382
Colombia	CP		8.12%		7,029,912		5,700,379		12,730,291		25,790,155		33,339,101		60,191,993		119,321,249		1,338,154		82,134,906		83,473,060		-		-		-		-
Brazil	US$		7.79%		469,815		7,492,580		7,962,395		16,343,599		8,949,758		2,144,472		27,437,829		644,936		12,599,186		13,244,122		17,532,685		17,877,446		6,352,599		41,762,730
Brazil	Real		7.47%		5,278,565		24,723,805		30,002,370		-		-		-		-		30,524,862		175,096,068		205,620,930		142,254,517		90,580,272		8,209,057		241,043,846

					52,503,961		78,753,216		131,257,177		177,459,336		79,839,161		89,977,464		347,275,961		77,007,952		324,538,353		401,546,305		345,704,646		138,492,715		79,093,234		563,290,595

F-129

Identification of bank borrowings by company


Taxpayer ID No. (RUT)	Company	Country	Financial Institution	Currency	Effective Interest Rate	Nominal Interest Rate	12-2012														12-2011
							Current						Non-current								Current						Non-current
							Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current		Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current
Foreign	Ampla	Brazil	Unibanco	Real	10.27%	10.29%		-		-		-		-		-		-		-		45,870		1,542,373		1,588,243		-		-		-		-
Foreign	Ampla	Brazil	Brasdesco	Real	9.75%	5.65%		4,723,977		-		4,723,977		-		-		-		-		5,982,354		13,453,719		19,436,073		-		-		-		-
Foreign	Ampla	Brazil	Banco do Brasil	Real	9.47%	9.29%		554,588		24,723,805		25,278,393		-		-		-		-		875,019		2,942,372		3,817,391		30,333,452		-		-		30,333,452
Foreign	Ampla	Brazil	Banco HSBC	Real	9.93%	9.77%		-		-		-		-		-		-		-		632,464		22,045,700		22,678,164		-		-		-		-
Foreign	Ampla	Brazil	Banco Itaú	Real	10.12%	10.20%		-		-		-		-		-		-		-		57,479		1,964,473		2,021,952		-		-		-		-
Foreign	Ampla	Brazil	Electrobras	Real	6.50%	6.50%		-		-		-		-		-		-		-		339,935		1,111,948		1,451,883		2,916,206		5,539,073		725,103		9,180,382
Foreign	Ampla	Brazil	Bndes	Real	9.06%	9.06%		-		-		-		-		-		-		-		6,488,408		16,888,622		23,377,030		33,192,137		52,961,281		3,133,364		89,286,782
Foreign	Ampla	Brazil	Banco Alfa	Real	10.23%	10.27%		-		-		-		-		-		-		-		1,779,341		12,975,006		14,754,347		-		-		-		-
Foreign	CGTF Fortaleza	Brazil	IFC - A	US$	7.98%	8.04%		276,653		3,174,804		3,451,457		6,851,156		6,773,346		-		13,624,502		344,277		3,510,015		3,854,292		7,427,750		7,100,739		4,604,499		19,132,988
Foreign	CGTF Fortaleza	Brazil	IFC - B	US$	3.03%	3.02%		91,826		4,013,768		4,105,594		8,681,755		-		-		8,681,755		114,099		4,162,847		4,276,946		8,990,990		4,835,251		-		13,826,241
Foreign	CGTF Fortaleza	Brazil	IFC - C	US$	12.09%	12.31%		101,336		304,008		405,344		810,688		2,176,412		2,144,472		5,131,572		108,598		365,176		473,774		875,946		5,584,166		-		6,460,112
Foreign	Companhia de Interconexao Energética S.A.	Brazil	Santander	Real	11.61%	11.80%		-		-		-		-		-		-		-		1,801,366		59,020,877		60,822,243		-		-		-		-
96,800,570-7	Chilectra S.A.	Chile	Bank credit lines	Ch$	6.60%	6.60%		46		-		46		-		-		-		-		-		-		-		-		-		-		-
94,271,000-3	Enersis S.A.	Chile	Banco Santander Chile	Ch$	2.10%	2.10%		53		-		53		-		-		-		-		-		-		-		-		-		-		-
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Banco Europeo de Investimentos	US$	5.49%	5.49%		-		-		-		-		-		-		-		19,073		173,334		192,407		237,999		357,290		1,748,100		2,343,389
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Eletrobras	Real	6.46%	6.46%		-		-		-		-		-		-		-		1,721,402		4,747,664		6,469,066		8,943,102		16,832,769		4,350,590		30,126,461
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Banco do Brazil	Real	15.61%	15.61%		-		-		-		-		-		-		-		1,310,254		4,235,607		5,545,861		5,443,423		-		-		5,443,423
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Bndes	Real	9.52%	9.52%		-		-		-		-		-		-		-		9,231,834		30,273,652		39,505,486		56,108,514		15,247,149		-		71,355,663
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Banco do Nordeste	Real	7.78%	7.78%		-		-		-		-		-		-		-		259,136		3,894,055		4,153,191		5,317,683		-		-		5,317,683
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Banco Europeo de Investimentos	US$	5.49%	5.49%		-		-		-		-		-		-		-		58,889		4,387,814		4,446,703		-		-		-		-
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Banco Agrario	CP	5.97%	5.81%		2,669,235		-		2,669,235		-		-		-		-		-		-		-		-		-		-		-
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	AV VILLAS	CP	6.32%	6.14%		2,460,550		-		2,460,550		-		-		-		-		-		-		-		-		-		-		-
Foreign	Edelnor	Peru	Banco de Crédito	Sol	5.43%	5.32%		41,569		124,706		166,275		332,548		1,050,422		2,117,918		3,500,888		37,891		127,413		165,304		305,625		-		3,584,598		3,890,223
Foreign	Edelnor	Peru	Banco de Crédito	Sol	5.43%	5.32%		58,199		174,596		232,795		465,590		1,470,611		2,965,089		4,901,290		60,638		203,903		264,541		489,101		-		5,157,627		5,646,728
Foreign	Edelnor	Peru	Banco de Interbank	Sol	6.90%	6.73%		32,026		96,077		128,103		256,207		2,016,376		-		2,272,583		32,758		110,153		142,911		264,223		-		2,430,861		2,695,084
Foreign	Edelnor	Peru	Banco Continental	Sol	5.43%	5.32%		-		-		-		-		-		-		-		99,201		333,576		432,777		800,145		-		9,525,160		10,325,305
Foreign	Edelnor	Peru	Banco de Crédito	Sol	5.43%	5.32%		41,569		124,706		166,275		332,548		1,050,422		2,117,918		3,500,888		37,891		127,413		165,304		305,625		-		3,584,598		3,890,223
Foreign	Edelnor	Peru	Banco de Crédito	Sol	5.43%	5.32%		41,569		124,706		166,275		332,548		1,050,422		2,117,918		3,500,888		37,891		127,413		165,304		305,625		-		3,584,598		3,890,223
Foreign	Edelnor	Peru	Banco de Crédito	Sol	5.43%	5.32%		36,026		108,077		144,103		288,205		910,362		1,835,528		3,034,095		32,360		108,816		141,176		261,016		-		3,097,880		3,358,896
Foreign	Edelnor	Peru	Banco de Crédito	Sol	5.43%	5.32%		16,627		49,882		66,509		133,019		420,169		847,167		1,400,355		15,156		50,965		66,121		122,250		-		1,433,839		1,556,089
Foreign	Edelnor	Peru	Banco de Crédito	Sol	5.43%	5.32%		69,281		207,843		277,124		554,247		1,750,704		3,529,863		5,834,814		63,151		212,355		275,506		509,375		-		5,974,330		6,483,705
Foreign	Edesur S.A.	Argentina	Banco de la Ciudad de Buenos Aires	Ar$	21.72%	21.33%		314,754		7,549,210		7,863,964		-		-		-		-		6,354,203		1,169,601		7,523,804		9,498,494		-		-		9,498,494
Foreign	Edesur S.A.	Argentina	Banco Provincia de Buenos Aires	Ar$	16.65%	15.50%		37,725		1,074,140		1,111,865		-		-		-		-		124,577		158,143		282,720		1,364,912		-		-		1,364,912
Foreign	Edesur S.A.	Argentina	Standard Bank	Ar$	22.83%	23.07%		769,536		2,086,114		2,855,650		621,207		-		-		621,207		213,681		718,530		932,211		4,195,131		-		-		4,195,131
Foreign	Edesur S.A.	Argentina	Banco Santander Río	Ar$	21.00%	21.00%		4,441,078		-		4,441,078		-		-		-		-		614,888		1,088,442		1,703,330		4,708,036		-		-		4,708,036
Foreign	Edesur S.A.	Argentina	BBVA	Ar$	19.55%	18.00%		-		-		-		-		-		-		-		128,257		2,499,512		2,627,769		-		-		-		-
Foreign	Edesur S.A.	Argentina	Citibank	Ar$	21.94%	20.00%		57,771		1,428,116		1,485,887		-		-		-		-		673,842		228,279		902,121		3,245,052		-		-		3,245,052
Foreign	Edesur S.A.	Argentina	Banco Itaú	Ar$	21.52%	19.65%		119,563		2,712,832		2,832,395		-		-		-		-		288,456		4,819,512		5,107,968		2,454,313		-		-		2,454,313

F-130

Identification of bank borrowings by company


Taxpayer ID No. (RUT)	Company	Country	Financial Institution	Currency	Effective Interest Rate	Nominal Interest Rate	12-2012							12-2011
							Current			Non-current				Current			Non-current
							Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non-current	Less than 90 days	More than 90 days	Total Current	One to Three Years	Three to Five Years	More than Five Years	Total Non-current
Foreign	Edesur S.A.	Argentina	Banco Galicia	Ar$	21.94%	20.00%	592,597	195,649	788,246	-	-	-	-	2,120,536	1,891,956	4,012,492	-	-	-	-
Foreign	Edesur S.A.	Argentina	Banco Macro	Ar$	23.67%	22.31%	2,014,971	-	2,014,971	-	-	-	-	151,298	508,762	660,060	3,474,143	-	-	3,474,143
Foreign	Edesur S.A.	Argentina	Citibank	Ar$	24.06%	21.75%	877,758	578,433	1,456,191	-	-	-	-	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Banco Santander Río	Ar$	21.26%	19.75%	48,076	689,891	737,967	411,852	-	-	411,852	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Banco Santander Río	Ar$	21.27%	20.69%	97,084	1,381,833	1,478,917	824,138	-	-	824,138	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Banco Santander Río	Ar$	21.27%	20.69%	121,354	1,727,291	1,848,645	1,030,173	-	-	1,030,173	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Banco Frances	Ar$	18.55%	22.00%	491,236	-	491,236	-	-	-	-	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Comafi	Ar$	25.07%	23.50%	238,213	-	238,213	-	-	-	-	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Banco Supervielle	Ar$	22.39%	19.75%	79,285	-	79,285	-	-	-	-	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Banco Santander Río	US$	6.24%	6.24%	199,159	-	199,159	-	-	-	-	-	-	-	-	-	-	-
Foreign	Chinango S.A.C.	Peru	Banco Continental	Sol	3.85%	3.80%	-	-	-	-	-	-	-	14,597	1,585,500	1,600,097	-	-	-	-
Foreign	Chinango S.A.C.	Peru	Banco Scotiabank	US$	4.07%	4.01%	161,573	923,528	1,085,101	2,391,649	2,288,243	12,109,598	16,789,490	166,062	558,407	724,469	2,423,556	17,774,668	-	20,198,224
Foreign	Chinango S.A.C.	Peru	Bank of Nova Scotia	US$	3.10%	3.06%	37,359	112,077	149,436	2,621,204	2,471,768	-	5,092,972	-	-	-	-	-	-	-
Foreign	Edegel	Peru	Banco de Crédito	US$	1.65%	1.65%	1,739,482	-	1,739,482	-	-	-	-	1,949,762	5,760,203	7,709,965	1,880,534	-	-	1,880,534
Foreign	Edegel	Peru	Banco Continental	US$	2.99%	2.96%	-	-	-	-	-	-	-	405,477	1,378,129	1,783,606	-	-	-	-
Foreign	Edegel	Peru	Banco Continental	US$	3.54%	3.49%	276,481	829,443	1,105,924	9,160,648	23,070,803	-	32,231,451	280,841	944,367	1,225,208	3,559,934	7,313,080	26,158,087	37,031,101
Foreign	Edegel	Peru	Banco Scotiabank	US$	3.45%	3.41%	-	-	-	-	-	-	-	8,155	1,878,060	1,886,215	-	-	-	-
Foreign	Edegel	Peru	Banco Continental	US$	3.00%	3.00%	-	-	-	-	-	-	-	260	-	260	-	-	-	-
Foreign	Emgesa	Colombia	Bancolombia	CP	9.41%	9.20%	428,684	1,286,051	1,714,735	5,805,307	7,495,253	13,520,587	26,821,147	326,504	20,008,140	20,334,644	-	-	-	-
Foreign	Emgesa	Colombia	Bancolombia	CP	9.41%	9.20%	131,424	394,271	525,695	1,838,073	2,414,481	4,407,478	8,660,032	99,148	6,208,686	6,307,834	-	-	-	-
Foreign	Emgesa	Colombia	BBVA Colombia	CP	9.41%	9.20%	1,158,673	3,476,018	4,634,691	15,690,942	20,258,627	36,544,265	72,493,834	361,976	22,181,880	22,543,856	-	-	-	-
Foreign	Emgesa	Colombia	AV VILLAS	CP	9.41%	9.20%	181,346	544,039	725,385	2,455,833	3,170,740	5,719,663	11,346,236	-	-	-	-	-	-	-
Foreign	Emgesa	Colombia	Banco Santander	CP	8.15%	7.91%	-	-	-	-	-	-	-	412,115	25,254,372	25,666,487	-	-	-	-
Foreign	Emgesa	Colombia	Banco Davivienda	CP	8.15%	7.91%	-	-	-	-	-	-	-	138,411	8,481,828	8,620,239	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Banco Supervielle	Ar$	20.75%	20.75%	1,483,661	-	1,483,661	-	-	-	-	123,454	-	123,454	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Banco Santander Río	Ar$	22.00%	22.00%	879,133	-	879,133	-	-	-	-	10,746,076	1,949,571	12,695,647	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Banco Nación Argentina	Ar$	18.85%	18.85%	946,327	1,855,665	2,801,992	411,921	-	-	411,921	1,382,931	1,533,096	2,916,027	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Citibank	Ar$	17.00%	17.00%	4,349,740	-	4,349,740	-	-	-	-	1,844,142	-	1,844,142	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Banco Ciudad	Ar$	18.75%	18.75%	395,870	-	395,870	-	-	-	-	4,670,705	-	4,670,705	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Standard Bank	Ar$	21.00%	21.00%	1,388,486	-	1,388,486	-	-	-	-	832,611	-	832,611	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Banco Itau	Ar$	23.75%	23.75%	2,459,388	-	2,459,388	-	-	-	-	3,503,302	-	3,503,302	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Banco Galicia	Ar$	18.75%	18.75%	2,031,944	-	2,031,944	-	-	-	-	1,105,942	-	1,105,942	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Banco Provincia de Buenos Aires	Ar$	18.09%	18.09%	96,871	122,911	219,782	-	-	-	-	-	-	-	-	-	-	-
Foreign	Endesa Costanera S.A.	Argentina	Credit Suisse International	US$	11.45%	11.45%	4,883,837	-	4,883,837	-	-	-	-	166,419	3,156,573	3,322,992	2,652,744	-	-	2,652,744
91,081,000-6	Endesa S.A. (Chile)	Chile	B.N.P. Paribas	US$	6.32%	5.98%	31,301	859,843	891,144	1,657,085	-	-	1,657,085	53,521	1,002,756	1,056,277	1,915,379	876,746	-	2,792,125
91,081,000-6	Endesa S.A. (Chile)	Chile	Export Development Corporation Loan	US$	1.82%	1.73%	347,952	354,206	702,158	689,651	-	-	689,651	379,501	764,980	1,144,481	1,132,904	-	-	1,132,904
91,081,000-6	Endesa S.A. (Chile)	Chile	Banco Bilbao Vizcaya Argentaria S.A.NY	US$	1.72%	1.12%	439,133	1,317,400	1,756,533	96,635,723	-	-	96,635,723	473,367	1,591,761	2,065,128	106,583,616	-	-	106,583,616
91,081,000-6	Endesa S.A. (Chile)	Chile	Banco Santander Chile (Linea Crédito)	Ch$	6.00%	6.00%	272	-	272	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Deutsche Bank	US$	8.30%	8.06%	881,121	2,547,013	3,428,134	3,918,502	-	-	3,918,502	518,208	1,530,246	2,048,454	3,576,867	402,643	-	3,979,510
Foreign	Hidroeléctrica El Chocón	Argentina	Standard Bank	US$	8.30%	8.06%	440,417	1,273,172	1,713,589	1,959,017	-	-	1,959,017	1,611,491	4,749,662	6,361,153	10,912,983	1,209,420	-	12,122,403
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Itau	US$	8.30%	8.06%	440,527	1,273,427	1,713,954	1,959,196	-	-	1,959,196	1,791,907	-	1,791,907	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Standard Bank - Syndicated I	Ar$	25.42%	23.31%	-	-	-	-	-	-	-	64,001	1,336,177	1,400,178	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Santander - Syndicated I	Ar$	25.42%	23.31%	-	-	-	-	-	-	-	80,629	1,707,695	1,788,324	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Hipotecario - Syndicated I	Ar$	25.42%	23.31%	354,694	340,398	695,092	-	-	-	-	55,506	1,125,918	1,181,424	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Galicia - Syndicated I	Ar$	25.42%	23.31%	-	-	-	-	-	-	-	26,301	535,888	562,189	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Itau - Syndicated II	Ar$	26.96%	24.11%	239,076	488,681	727,757	230,121	-	-	230,121	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Standard Bank - Syndicated II	Ar$	26.96%	24.11%	527,542	1,078,428	1,605,970	507,222	-	-	507,222	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Santander - Syndicated II	Ar$	26.96%	24.11%	383,587	784,144	1,167,731	368,840	-	-	368,840	329,514	1,108,036	1,437,550	6,245,072	1,229,220	-	7,474,292
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Hipotecario - Syndicated II	Ar$	26.96%	24.11%	190,602	389,550	580,152	183,696	-	-	183,696	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Galicia - Syndicated II	Ar$	26.96%	24.11%	190,906	390,193	581,099	183,881	-	-	183,881	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Ciudad - Syndicated II	Ar$	26.96%	24.11%	152,374	311,411	463,785	146,892	-	-	146,892	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Galicia - Syndicated III	Ar$	26.95%	24.10%	614,638	779,040	1,393,678	1,679,513	-	-	1,679,513	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Itau - Syndicated III	Ar$	26.95%	24.10%	614,638	779,040	1,393,678	1,679,513	-	-	1,679,513	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Standard Bank - Syndicated III	Ar$	26.95%	24.10%	614,638	779,040	1,393,678	1,679,513	-	-	1,679,513	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Santander - Syndicated III	Ar$	26.95%	24.10%	614,638	779,040	1,393,678	1,679,513	-	-	1,679,513	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Macro	Ar$	18.81%	18.00%	87,619	2,034,700	2,122,319	-	-	-	-	233,981	2,275,667	2,509,648	2,994,506	-	-	2,994,506
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Macro I	Ar$	23.14%	21.00%	295,652	-	295,652	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Standard Bank	Ar$	23.14%	21.00%	198,116	-	198,116	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Santander Río	Ar$	22.42%	20.75%	98,949	-	98,949	-	-	-	-	-	-	-	-	-	-	-
Foreign	Hidroeléctrica El Chocón	Argentina	Citibank	Ar$	19.84%	BPC + 5.10%	-	-	-	-	-	-	-	112,503	1,115,167	1,227,670	1,471,923	-	-	1,471,923
Foreign	Hidroeléctrica El Chocón	Argentina	BBVA	Ar$	19.84%	BPC + 5.10%	-	-	-	-	-	-	-	152,645	1,527,554	1,680,199	2,019,288	-	-	2,019,288
Foreign	Hidroeléctrica El Chocón	Argentina	Banco Industrial de Azul	Ar$	19.84%	BPC + 5.10%	-	-	-	-	-	-	-	329,514	1,108,036	1,437,550	6,245,072	1,229,220	-	7,474,292

				Total			52,503,961	78,753,216	131,257,177	177,459,336	79,839,161	89,977,464	347,275,961	77,007,952	324,538,353	401,546,305	345,704,646	138,492,715	79,093,234	563,290,595

F-131

Secured and unsecured liabilities

Secured and unsecured liabilities by currency and maturity


						Current						Non-current								Current						Non-current
						Maturity						Maturity								Maturity						Maturity
Country	Currency	Nominal Rate			One to Three Months		Three to Twelve Months		Total Current at 12-31-2012		One to Three Years		Three to Five Years		More than Five Years		Total non-Current at 12-31-2012		One to Three Months		Three to Twelve Months		Total Current at 12-31-2011		One to Three Years		Three to Five Years		More than Five Years		Total Non-Current at 12-31-2011
						ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$

Chile	US$		7.71	%		14,737,200		230,223,447		244,960,647		321,100,837		152,918,883		397,654,469		871,674,189		22,439,241		48,971,036		71,410,277		481,039,815		346,571,275		425,876,193		1,253,487,283
Chile	U.F.		5.57	%		6,471,264		26,447,107		32,918,371		64,353,555		62,344,872		439,118,433		565,816,860		41,003,385		39,199,072		80,202,457		89,539,138		263,688,193		527,887,200		881,114,531
Peru	US$		6.89	%		628,048		1,884,143		2,512,191		12,047,614		12,454,106		22,585,830		47,087,550		853,625		2,238,831		3,092,456		16,267,919		28,913,608		19,449,710		64,631,237
Peru	Sol		6.52	%		23,539,322		33,223,851		56,763,173		82,309,019		33,206,836		70,650,808		186,166,663		31,909,724		18,212,792		50,122,516		92,722,951		73,395,355		17,029,264		183,147,570
Argentina	Ar$		0.00	%		-		-		-		-		-				-		116,551		4,100,169		4,216,720		-		-		-		-
Colombia	CP		8.01	%		41,109,039		101,282,166		142,391,205		299,961,187		293,630,963		646,033,188		1,239,625,338		17,854,990		68,624,369		86,479,359		299,425,050		335,136,989		589,777,719		1,224,339,758
Brazil	Real		11.58	%		9.870.157		55,941,012		65,811,169		132,005,212		195,057,347		97,529,513		424,592,072		11,815,750		134,615,237		146,430,987		123,922,410		200,558,653		90,131,132		414,612,195

						96,355,030		449,001,726		545,356,756		911,777,424		749,613,007		1,673,572,241		3,334,962,672		125,993,266		315,961,506		441,954,772		1,102,917,283		1,248,264,073		1,670,151,218		4,021,332,574

F-132

Secured and unsecured liabilities by company


Taxpayer ID No. (RUT)	Company	Country	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	12-2012														12-2011
								Current						Non-current								Current						Non-current
								Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current		Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current
Foreign	Ampla	Brazil	Bonds	Brazil	Real	9.56%	9.56%		-		-		-		-		-		-		-		6,698,731		102,230,946		108,929,677		59,162,266		133,237,309		-		192,399,575
Foreign	Ampla	Brazil	Bonds, 1st series	Brazil	Real	9.47%	9.55%		649,029		1,947,086		2,596,115		18,249,614		14,355,442		-		32,605,056		-		-		-		-		-		-		-
Foreign	Ampla	Brazil	Bonds, 2nd series	Brazil	Real	13.89%	13.99%		1,306,206		16,457,896		17,764,102		30,303,386		-		-		30,303,386		-		-		-		-		-		-		-
Foreign	Ampla	Brazil	Bonds, 2nd series	Brazil	Real	13.49%	14.21%		1,563,703		4,691,110		6,254,813		12,509,626		39,253,525		16,499,357		68,262,508		-		-		-		-		-		-		-
Foreign	Ampla	Brazil	Bonds, 1st series	Brazil	Real	8.30%	8.38%		486,106		1,458,317		1,944,423		3,888,844		25,374,189		-		29,263,033		-		-		-		-		-		-		-
Foreign	Ampla	Brazil	Bonds, 2nd series	Brazil	Real	11.40%	11.69%		2,063,384		6,190,152		8,253,536		16,507,071		39,266,574		53,772,545		109,546,190		-		-		-		-		-		-		-
Foreign	Codensa	Colombia	B8	Colombia	CP	9.65%	9.32%		1,578,308		4,734,924		6,313,232		69,271,323		-		-		69,271,323		1,601,595		5,385,582		6,987,177		74,917,478		-		-		74,917,478
Foreign	Codensa	Colombia	B102	Colombia	CP	8.57%	8.31%		2,233,916		6,701,749		8,935,665		17,871,330		117,176,843		-		135,048,173		2,268,235		7,627,252		9,895,487		18,295,433		139,590,884		-		157,886,317
Foreign	Codensa	Colombia	B502	Colombia	CP	6.81%	6.93%		-		-		-		-		-		-		-		142,540		9,063,816		9,206,356		-		-		-		-
Foreign	Codensa	Colombia	B503	Colombia	CP	8.17%	7.93%		452,748		24,509,254		24,962,002		-		-		-		-		369,477		1,242,417		1,611,894		24,349,062		-		-		24,349,062
Foreign	Codensa	Colombia	B503	Colombia	CP	9.29%	8.98%		457,666		21,816,289		22,273,955		-		-		-		-		467,694		1,572,686		2,040,380		22,071,605		-		-		22,071,605
Foreign	Codensa	Colombia	B103	Colombia	CP	8.83%	8.55%		464,493		1,393,478		1,857,971		3,715,942		3,715,942		23,519,736		30,951,620		469,953		1,580,283		2,050,236		3,790,614		32,393,688		-		36,184,302
Foreign	Codensa	Colombia	B304	Colombia	CP	6.18%	6.04%		21,879,751		-		21,879,751		-		-		-		-		346,784		1,166,108		1,512,892		21,620,973		-		-		21,620,973
Foreign	Codensa	Colombia	B604	Colombia	CP	7.15%	6.97%		682,706		2,048,119		2,730,825		5,461,651		39,717,086		-		45,178,737		717,221		2,411,754		3,128,975		5,785,056		46,931,965		-		52,717,021
Foreign	Coelce	Brazil	Itaú 2	Brazil	Real	12.36%	12.22%		942,362		16,618,350		17,560,712		15,675,987		-		-		15,675,987		2,539,943		23,718,519		26,258,462		43,973,620		34,824,619		-		78,798,239
Foreign	Coelce	Brazil	Itaú 1	Brazil	Real	10.26%	10.30%		563,189		1,689,567		2,252,756		16,501,261		13,122,127		-		29,623,388		-		-		-		-		-		-		-
Foreign	Coelce	Brazil	Itaú 2	Brazil	Real	11.48%	11.57%		2,296,178		6,888,534		9,184,712		18,369,423		63,685,490		27,257,611		109,312,524		2,577,076		8,665,772		11,242,848		20,786,524		32,496,725		90,131,132		143,414,381
Foreign	Edelnor	Peru	Rimac Internacional Cia de Seguros	Peru	Sol	5.44%	5.37%		65,162		195,487		260,649		4,844,664		-		-		4,844,664		63,823		214,613		278,436		5,077,124		-		-		5,077,124
Foreign	Edelnor	Peru	Rimac Internacional Cia de Seguros	Peru	Sol	6.50%	6.40%		78,864		236,592		315,456		4,905,580		-		-		4,905,580		76,203		256,244		332,447		5,180,728		-		-		5,180,728
Foreign	Edelnor	Peru	AFP Integra	Peru	Sol	6.50%	6.40%		157,047		471,140		628,187		9,793,310		-		-		9,793,310		151,944		510,933		662,877		10,342,337		-		-		10,342,337
Foreign	Edelnor	Peru	Retirement Insurance Fund for Non-commissioned Officers and Specialists – Fosersoe	Peru	Sol	8.75%	8.57%		122,881		368,642		491,523		6,370,075		-		-		6,370,075		126,147		424,187		550,334		1,017,494		6,418,045		-		7,435,539
Foreign	Edelnor	Peru	AFP Integra	Peru	Sol	8.16%	8.00%		68,809		206,427		275,236		550,471		3,402,611		-		3,953,082		70,593		237,379		307,972		569,399		4,271,435		-		4,840,834
Foreign	Edelnor	Peru	AFP Horizonte	Peru	Sol	7.22%	7.09%		50,772		152,315		203,087		406,174		2,951,787		-		3,357,961		52,086		175,146		227,232		420,122		3,482,779		-		3,902,901
Foreign	Edelnor	Peru	AFP Integra	Peru	Sol	8.00%	7.85%		101,946		305,837		407,783		815,566		5,175,028		-		5,990,594		104,593		351,709		456,302		843,643		6,430,925		-		7,274,568
Foreign	Edelnor	Peru	FCR – Macrofondo	Peru	Sol	6.66%	6.55%		46,822		2,925,647		2,972,469		-		-		-		-		48,033		161,519		209,552		3,034,955		-		-		3,034,955
Foreign	Edelnor	Peru	AFP Integra	Peru	Sol	5.91%	5.82%		55,380		166,139		221,519		4,050,553		-		-		4,050,553		56,814		191,045		247,859		458,259		3,910,505		-		4,368,764
Foreign	Edelnor	Peru	AFP Prima	Peru	Sol	6.94%	6.82%		129,963		389,890		519,853		8,376,812		-		-		8,376,812		133,328		448,335		581,663		1,075,419		8,019,674		-		9,095,093
Foreign	Edelnor	Peru	AFP Prima	Peru	Sol	6.81%	6.70%		79,787		239,362		319,149		4,853,567		-		-		4,853,567		81,845		275,214		357,059		5,284,017		-		-		5,284,017
Foreign	Edelnor	Peru	AFP Prima	Peru	Sol	7.13%	7.00%		83,444		250,333		333,777		667,555		4,860,882		-		5,528,437		85,597		287,833		373,430		690,422		5,790,825		-		6,481,247
Foreign	Edelnor	Peru	AFP Profuturo	Peru	Sol	7.72%	7.58%		53,186		2,851,853		2,905,039		-		-		-		-		54,563		183,474		238,037		2,962,950		-		-		2,962,950
Foreign	Edelnor	Peru	AFP Profuturo	Peru	Sol	8.06%	7.91%		108,459		5,777,404		5,885,863		-		-		-		-		111,264		374,141		485,405		6,004,573		-		-		6,004,573
Foreign	Edelnor	Peru	AFP Horizonte	Peru	Sol	6.56%	6.46%		90,609		271,826		362,435		5,685,232		-		-		5,685,232		92,948		312,552		405,500		6,177,926		-		-		6,177,926
Foreign	Edelnor	Peru	Rimac Internacional Cia de Seguros	Peru	Sol	7.06%	6.94%		99,182		297,547		396,729		793,458		6,161,764		-		6,955,222		101,873		342,563		444,436		821,704		6,921,650		-		7,743,354
Foreign	Edelnor	Peru	AFP Prima	Peru	Sol	6.63%	6.52%		62,025		186,076		248,101		4,085,997		-		-		4,085,997		63,749		214,363		278,112		514,191		3,917,515		-		4,431,706
Foreign	Edelnor	Peru	AFP Prima	Peru	Sol	7.44%	7.30%		104,449		313,346		417,795		835,588		835,588		6,746,909		8,418,085		107,277		360,734		468,011		865,289		2,512,167		6,209,886		9,587,342
Foreign	Edelnor	Peru	Rimac Internacional Cia de Seguros	Peru	Sol	6.50%	6.40%		60,855		182,566		243,421		486,841		4,221,751		-		4,708,592		62,548		210,325		272,873		504,506		4,816,026		-		5,320,532

F-133

Secured and unsecured liabilities by company


Taxpayer ID No. (RUT)	Company	Country	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	12-2012														12-2011
								Current						Non-current								Current						Non-current
								Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current		Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current
Foreign	Edelnor	Peru	FCR - Macrofondo	Peru	Sol	7.03%	6.91%		65,829		197,487		263,316		526,631		526,631		4,040,453		5,093,715		68,516		230,393		298,909		552,643		5,457,537		-		6,010,180
Foreign	Edelnor	Peru	9th issue, Series A	Peru	Sol	6.28%	6.19%		119,124		357,371		476,495		952,989		952,989		9,575,198		11,481,176		-		-		-		-		-		-		-
Foreign	Edelnor	Peru	11th issue, Series A	Peru	Sol	6.06%	5.97%		143,745		431,236		574,981		1,149,961		1,149,961		16,862,736		19,162,658		-		-		-		-		-		-		-
Foreign	Edelnor	Peru	Essalud Health Insurance	Peru	Sol	7.84%	7.70%		755,962		-		755,962		-		-		-		-		15,147		821,547		836,694		-		-		-		-
Foreign	Edelnor	Peru	AFP Prima	Peru	Sol	6.84%	6.73%		5,664,849		-		5,664,849		-		-		-		-		98,656		6,111,343		6,209,999		-		-		-		-
Foreign	Edelnor	Peru	Mapfre Peru Cia de Seguros	Peru	Sol	6.28%	6.19%		3,814,063		-		3,814,063		-		-		-		-		60,381		203,039		263,420		3,893,541		-		-		3,893,541
Foreign	Edelnor	Peru	AFP Profuturo	Peru	Sol	8.31%	8.15%		94,076		282,228		376,304		5,147,475		-		-		5,147,475		96,506		324,515		421,021		778,412		4,863,685		-		5,642,097
Foreign	Edelnor	Peru	AFP Profuturo	Peru	Sol	7.91%	7.76%		-		-		-		-		-		-		-		51,945		2,662,041		2,713,986		-		-		-		-
Foreign	Edelnor	Peru	AFP Profuturo	Peru	Sol	7.56%	7.42%		5,669,822		-		5,669,822		-		-		-		-		6,276,791		-		6,276,791		-		-		-		-
Foreign	Edelnor	Peru	13^th issue, Series A	Peru	Sol	5.56%	5.49%		133,594		400,781		534,375		1,068,749		1,068,749		11,881,733		14,019,231		-		-		-		-		-		-		-
Foreign	Edelnor	Peru	AFP Profuturo	Peru	Sol	5.77%	5.69%		-		-		-		-		-		-		-		3,926,418		-		3,926,418		-		-		-		-
Foreign	Edelnor	Peru	AFP Horizonte	Peru	Sol	6.06%	5.97%		-		-		-		-		-		-		-		7,975,989		-		7,975,989		-		-		-		-
Foreign	Edelnor	Peru	AFP Profuturo	Peru	Sol	6.67%	6.56%		-		-		-		-		-		-		-		6,065,488		-		6,065,488		-		-		-		-
Foreign	Edelnor	Peru	AFP Profuturo	Peru	Sol	7.97%	7.81%		-		-		-		-		-		-		-		4,936,463		-		4,936,463		-		-		-		-
Foreign	Edelnor	Peru	Rimac Internacional Cia de Seguros	Peru	Sol	5.00%	4.94%		90,003		270,010		360,013		720,026		720,026		10,360,492		11,800,544		-		-		-		-		-		-		-
Foreign	Edesur S.A.	Argentina	oeds7	Argentina	Ar$	12.28%	11.75%		-		-		-		-		-		-		-		116,551		4,100,169		4,216,720		-		-		-		-
94,271,000-3	Enersis S.A.	Chile	Yankee bonds 2016	USA	US$	7.76%	7.40%		2,297,908		6,893,723		9,191,631		18,383,260		128,761,093		-		147,144,353		2,492,775		8,382,298		10,875,073		20,106,557		158,089,452		-		178,196,009
94,271,000-3	Enersis S.A.	Chile	Yankee bonds 2026	USA	US$	7.76%	6.60%		7,041		21,124		28,165		56,331		56,331		664,287		776,949		7,638		25,685		33,323		61,611		178,874		660,104		900,589
94,271,000-3	Enersis S.A.	Chile	Yankee bonds 2014	USA	US$	7.69%	7.38%		3,166,579		9,499,738		12,666,317		168,631,075		-		-		168,631,075		9,552,437		5,637,390		15,189,827		195,829,642		-		-		195,829,642
94,271,000-3	Enersis S.A.	Chile	UF 269 bonds	Chile	U.F.	7.02%	5.75%		669,150		4,474,479		5,143,629		10,049,549		9,701,503		20,334,599		40,085,651		837,156		5,068,678		5,905,834		10,912,682		27,372,736		11,324,847		49,610,265
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	The Bank of New York Mellon – First issue S-1	USA	US$	7.96%	7.88%		1,975,290		5,925,870		7,901,160		15,802,321		15,802,321		171,658,937		203,263,579		703,310		2,364,976		3,068,286		5,672,852		16,469,819		84,974,171		107,116,842
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	The Bank of New York Mellon – First issue S-2	USA	US$	7.40%	7.33%		630,588		1,891,764		2,522,352		5,044,703		5,044,703		78,366,028		88,455,434		2,204,773		7,413,852		9,618,625		17,783,553		51,630,453		177,679,777		247,093,783
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	The Bank of New York Mellon – First issue S-3	USA	US$	8.26%	8.13%		406,804		1,220,413		1,627,217		3,254,435		3,254,435		146,965,217		153,474,087		2,384,734		8,018,994		10,403,728		19,235,104		109,486,718		-		128,721,822
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	The Bank of New York Mellon - 144 - A	USA	US$	8.50%	8.35%		4,127,302		198,393,750		202,521,052		-		-		-		-		4,635,971		15,589,088		20,225,059		218,659,499		-		-		218,659,499
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	The Bank of New York Mellon - 144 - A	USA	US$	8.83%	8.63%		2,125,688		6,377,065		8,502,753		109,928,712		-		-		109,928,712		457,603		1,538,753		1,996,356		3,690,997		10,715,959		162,562,141		176,969,097
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	Banco Santander Chile - 317 Series-H	Chile	U.F.	7.17%	6.20%		1,684,588		9,620,049		11,304,637		21,363,797		19,703,160		79,761,211		120,828,168		2,124,125		11,532,964		13,657,089		24,422,163		58,670,925		66,097,899		149,190,987
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	Banco Santander Chile - 522 Series-M	Chile	U.F.	4.82%	4.75%		4,117,526		12,352,579		16,470,105		32,940,209		32,940,209		339,022,623		404,903,041		4,973,783		16,725,028		21,698,811		40,118,205		136,748,818		305,217,831		482,084,854
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	Banco Santander Chile - 318 Series-K	Chile	U.F.	3.86%	3.86%		-		-		-		-		-		-		-		1,746,368		5,872,402		7,618,770		14,086,088		40,895,714		145,246,623		200,228,425
91,081,000-6	Empresa Nacional de Electricidad S.A.	Chile	Banco Santander Chile - 264 Series-F	Chile	U.F.	6.44%	6.44%		-		-		-		-		-		-		-		31,321,953		-		31,321,953		-		-		-		-
Foreign	Emgesa S.A. E.S.P.	Colombia	A-10 Bonds	Colombia	CP	7.95%	7.72%		1,102,280		3,306,839		4,409,119		62,006,104		-		-		62,006,104		1,150,327		3,868,134		5,018,461		9,278,465		-		56,536,718		65,815,183
Foreign	Emgesa S.A. E.S.P.	Colombia	A102 Bonds	Colombia	CP	7.95%	7.72%		209,956		629,869		839,825		11,810,678		-		-		11,810,678		216,825		729,104		945,929		1,748,896		10,768,120		-		12,517,016
Foreign	Emgesa S.A. E.S.P.	Colombia	A5 Bonds	Colombia	CP	8.06%	8.06%		223,748		671,245		894,993		13,536,136		-		-		13,536,136		179,093		602,226		781,319		14,001,389		-		-		14,001,389
Foreign	Emgesa S.A. E.S.P.	Colombia	B09-09 Bonds	Colombia	CP	7.38%	7.19%		1,325,639		3,976,917		5,302,556		10,605,111		10,605,111		62,175,621		83,385,843		1,328,332		4,466,698		5,795,030		10,714,236		84,115,563		-		94,829,799
Foreign	Emgesa S.A. E.S.P.	Colombia	B10 Bonds	Colombia	CP	8.71%	8.44%		946,998		2,840,995		3,787,993		7,575,987		7,575,987		47,759,102		62,911,076		989,794		3,328,320		4,318,114		7,983,617		-		65,971,663		73,955,280
Foreign	Emgesa S.A. E.S.P.	Colombia	B-103 Bonds	Colombia	CP	9.03%	8.74%		894,296		2,682,888		3,577,184		7,154,367		50,204,631		-		57,358,998		1,129,556		3,798,288		4,927,844		9,110,927		-		62,840,794		71,951,721
Foreign	Emgesa S.A. E.S.P.	Colombia	B12 Bonds	Colombia	CP	9.27%	9.27%		555,900		1,667,701		2,223,601		4,447,203		4,447,203		32,223,666		41,118,072		556,858		1,872,513		2,429,371		4,491,583		13,040,277		28,416,894		45,948,754
Foreign	Emgesa S.A. E.S.P.	Colombia	B15 Bonds	Colombia	CP	8.83%	8.56%		339,573		1,018,719		1,358,292		2,716,583		2,716,583		23,403,981		28,837,147		354,285		1,191,331		1,545,616		2,857,637		8,296,492		21,943,442		33,097,571
Foreign	Emgesa S.A. E.S.P.	Colombia	E5-09 Bonds	Colombia	CP	9.04%	8.75%		577,113		1,731,338		2,308,451		26,317,195		-		-		26,317,195		569,828		1,916,126		2,485,954		28,105,888		-		-		28,105,888
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign bonds	Colombia	CP	10.17%	10.17%		618,169		1,854,506		2,472,675		4,945,349		4,945,349		31,993,565		41,884,263		610,366		2,052,440		2,662,806		4,923,173		-		43,251,722		48,174,895
Foreign	Emgesa S.A. E.S.P.	Colombia	Quimbo bonds	Colombia	CP	10.17%	10.17%		4,442,297		13,326,891		17,769,188		35,538,377		35,538,377		229,912,869		300,989,623		4,386,227		14,749,291		19,135,518		35,379,018		-		310,816,486		346,195,504
Foreign	Emgesa S.A. E.S.P.	Colombia	Quimbo B10 bonds	Colombia	CP	6.39%	6.24%		1,264,032		3,792,096		5,056,128		10,112,255		10,112,255		106,512,256		126,736,766		-		-		-		-		-		-		-
Foreign	Emgesa S.A. E.S.P.	Colombia	Quimbo B15 bonds	Colombia	CP	6.39%	6.24%		859,450		2,578,349		3,437,799		6,875,596		6,875,596		88,532,392		102,283,584		-		-		-		-		-		-		-
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	US$	6.57%	6.47%		79,897		239,692		319,589		639,178		639,178		4,814,505		6,092,861		97,652		235,722		333,374		616,363		1,789,469		5,500,435		7,906,267
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	Sol	6.41%	6.31%		73,875		221,624		295,499		590,997		590,997		6,023,737		7,205,731		160,276		-		160,276		-		-		10,819,378		10,819,378
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	Sol	6.38%	6.28%		73,509		220,527		294,036		588,072		588,072		5,159,550		6,335,694		79,552		267,504		347,056		4,950,085		-		-		4,950,085
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	Sol	6.86%	6.75%		63,196		189,587		252,783		3,923,716		-		-		3,923,716		78,051		262,457		340,508		4,868,653		-		-		4,868,653
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	Sol	6.61%	6.50%		4,770,062		-		4,770,062		-		-		-		-		77,676		261,195		338,871		5,051,067		-		-		5,051,067
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	Sol	6.54%	6.44%		75,338		4,744,218		4,819,556		-		-		-		-		73,923		248,577		322,500		5,114,463		-		-		5,114,463
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	Sol	6.74%	6.63%		77,532		4,771,525		4,849,057		-		-		-		-		89,628		301,387		391,015		5,873,636		-		-		5,873,636
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	Sol	6.70%	6.59%		87,352		262,056		349,408		5,400,952		-		-		5,400,952		77,300		259,934		337,234		4,919,966		-		-		4,919,966
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	US$	6.44%	6.34%		78,353		235,060		313,413		626,827		626,827		7,948,123		9,201,777		83,851		281,959		365,810		2,639,913		-		8,220,849		10,860,762
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	US$	9.20%	9.00%		108,049		324,147		432,196		5,049,991		-		-		5,049,991		115,630		388,820		504,450		5,903,654		-		-		5,903,654
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	US$	7.93%	7.78%		78,482		235,446		313,928		627,856		627,856		4,249,866		5,505,578		83,988		282,422		366,410		677,444		6,208,170		-		6,885,614
Foreign	Edegel S.A.A	Peru	Banco Continental	Peru	US$	7.25%	7.13%		55,926		167,777		223,703		3,285,038		-		-		3,285,038		59,850		201,252		261,102		3,783,487		-		-		3,783,487
Foreign	Edegel S.A.A	Peru	Banco Scotiabank	Peru	US$	6.74%	6.63%		81,827		245,481		327,308		654,617		4,978,803		-		5,633,420		87,568		294,460		382,028		706,319		6,190,863		-		6,897,182
Foreign	Edegel S.A.A	Peru	Banco Scotiabank	Peru	US$	6.09%	6.00%		74,108		222,323		296,431		592,861		5,010,196		-		5,603,057		79,307		266,681		345,988		639,685		6,096,813		-		6,736,498
Foreign	Edegel S.A.A	Peru	Banco Scotiabank	Peru	US$	5.87%	5.78%		71,406		214,217		285,623		571,246		571,246		5,573,336		6,715,828		85,503		287,515		373,018		689,660		6,853,252		-		7,542,912
Foreign	Chinango S.A.C.	Peru	Banco Continental	Peru	US$	6.15%	6.06%		-		-		-		-		-		-		-		75,800		254,886		330,686		611,394		1,775,041		5,728,426		8,114,861
Foreign	Chinango S.A.C.	Peru	Banco Continental	Peru	Sol	6.57%	6.47%		75,703		4,870,634		4,946,337		-		-		-		-		75,424		253,624		329,048		608,367		6,582,587		-		7,190,954
Foreign	Chinango S.A.C.	Peru	Banco Continental	Peru	Sol	6.25%	6.16%		72,046		216,138		288,184		4,718,008		-		-		4,718,008		64,842		218,041		282,883		4,267,060		-		-		4,267,060


			Total						96,355,030		49,001,726		545,356,756		911,777,424		749,613,007		1,673,572,241		3,334,962,672		125,993,266		315,961,506		441,954,772		1,102,917,283		1,248,264,073		1,670,151,218		4,021,332,574

F-134

c)	Financial lease obligations

Financial lease obligations by company


Taxpayer ID No. (RUT)	Company	Country	ID No. Financial Institution	Financial Institution	Country	Currency	Nominal Interest Rate	12-2012														12-2011
								Current						Non-current								Current						Non-current
								Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current		Less than 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current
91,081,000-6	Endesa S.A. (Chile)	Chile	87,509,100-K	Abengoa Chile	Chile	US$	6.50%		517,486		1,552,682		2,070,168		4,142,238		4,145,057		13,854,905		22,142,200		567,586		1,900,568		2,468,154		4,556,135		12,220,275		10,867,880		27,644,290
Foreign	Edegel	Peru	Foreign	Banco Scotiabank	Peru	US$	2.13%		1,406,430		4,177,025		5,583,455		12,608,401		17,546,542		-		30,154,943		2,137,134		6,953,795		9,090,929		11,858,222		27,292,271		-		39,150,493
Foreign	Edelnor	Peru	Foreign	BBVA	Peru	Sol	5.77%		1,230,672		3,009,713		4,240,385		2,238,071		-		-		2,238,071		1,178,706		3,660,137		4,838,843		2,604,306		-		-		2,604,306
Foreign	Edesur S.A.	Argentina	Foreign	COMAFI	Argentina	Ar$	25.60%		216,766		313,356		530,122		216,179		-		-		216,179		170,578		411,253		581,831		673,700		-		-		673,700

			Total						3,371,354		9,052,776		12,424,130		19,204,889		21,691,599		13,854,905		54,751,393		4,054,004		12,925,753		16,979,757		19,692,363		39,512,546		10,867,880		70,072,789

d)	Other liabilities

Other

liabilities by company


Taxpayer ID No. (RUT)	Company	Country	ID No. Financial Institution	Financial Institution	Country	Currency	Nominal Interest Rate	12-2012														12-2011
								Current						Non-current								Current						Non-current
								Less than 90 days		Morethan 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current		Lessthan 90 days		More than 90 days		Total Current		One to Three Years		Three to Five Years		More than Five Years		Total Non- current
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Mitsubishi (secured debt)	Argentina	US$	7.42%		56,264,078		-		56,264,078		-		-		-		-		14,958,554		10,030,787		24,989,341		32,747,272		24,243,194		-		56,990,466
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Mitsubishi (unsecured debt)	Argentina	US$	7.42%		11,534,186		-		11,534,186		-		-		-		-		2,296,618		67,527		2,364,145		161,976		1,139,597		-		1,301,573
Foreign	Endesa Costanera S.A.	Argentina	Foreign	Other	Argentina	Ar$	17.29%		799,346		5,846,518		6,645,864		6,019,282		-		-		6,019,282		547,198		884,765		1,431,963		-		-		-		-
96,830,980-3	Inversiones Gas Atacama Holding Ltda.	Chile	96,963,440-6	SC GROUP	Chile	US$	7.50%		6,659,064		-		6,659,064		-		-		-		-		10,193,375		-		10,193,375		-		-		-		-
96,827,970-K	Endesa Eco S.A.	Chile	96,601,250-1	Inversiones Centinela S.A.	Chile	US$	6.10%		2,017,319		-		2,017,319		-		-		-		-		-		3,930,734		3,930,734		-		-		-		-
Foreign	Ampla Energía E Servicios S.A.	Brazil	Foreign	Eletrobrás	Brazil	Real	6.50%		285,377		965,266		1,250,643		3,045,792		2,592,406		1,861,196		7,499,394		-		-		-		-		-		-		-
Foreign	Ampla Energía E Servicios S.A.	Brazil	Foreign	Bndes	Brazil	Real	9.06%		4,536,007		13,214,919		17,750,926		31,774,969		27,224,080		14,032,389		73,031,438		-		-		-		-		-		-		-
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Eletrobras	Brazil	Real	6.46%		1,190,648		3,151,597		4,342,245		6,954,127		6,017,081		8,923,825		21,895,033		-		-		-		-		-		-		-
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Banco do Brasil	Brazil	US$	4.62%		16,441		113,614		130,055		149,411		115,228		1,694,259		1,958,898		-		-		-		-		-		-		-
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Banco do Brasil	Brazil	Real	15.61%		1,116,763		3,235,164		4,351,927		935,799		-		-		935,799		-		-		-		-		-		-		-
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	BNDES	Brazil	Real	9.52%		3,934,967		9,755,961		13,690,928		12,079,881		-		-		12,079,881		-		-		-		-		-		-		-
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Banco do Nordeste	Brazil	Real	7.78%		2,267,540		8,719,128		10,986,668		22,974,521		11,730,771		6,498,966		41,204,258		-		-		-		-		-		-		-
Foreign	Compañía Energética Do Ceará S.A.	Brazil	Foreign	Faelce	Brazil	Real	13.22%		121,287		3,117,565		3,238,852		1,498,141		-		-		1,498,141		-		-		-		-		-		-		-

			Total						90,743,023		48,119,732		138,862,755		85,431,923		47,679,566		33,010,635		166,122,124		27,995,745		14,913,813		42,909,558		32,909,248		25,382,791		-		58,292,039

F-135

APPENDIX 5 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY

This appendix forms an integral part of the Enersis financial statements.

The detail of assets and liabilities denominated in foreign currencies is the following:

ASSETS

Foreign Currency

Functional
Currency

12-31-2012
ThCh$

12-31-2011
ThCh$

CURRENT ASSETS

Cash and cash equivalents

34,346,077

42,323,083

U.S. dollar

Chilean peso

29,667,476

22,805,258

U.S. dollar

Colombian peso

10,947

5,634

U.S. dollar

Peruvian sol

4,233,557

3,201,968

U.S. dollar

Argentine peso

434,097

16,310,223

Trade and other current receivables

6,803,538

10,100,793

U.S. dollar

Chilean peso

6,803,538

10,100,793

Accounts receivable from related companies

580,405

379,862

U.S. dollar

Chilean peso

580,405

379,862

Total current assets other than assets classified as held for
sale and discontinued operations

41,730,020

52,803,738

TOTAL CURRENT ASSETS

41,730,020

52,803,738

Investments accounted for using the equity method

9,030,441

9,733,400

U.S. dollar

Chilean peso

9,030,441

9,733,400

Goodwill

426,209,853

477,068,142

Brazilian real

Peruvian sol

8,703,399

10,361,690

Brazilian real

Chilean peso

272,442,268

313,990,020

Colombian peso

Chilean peso

11,742,640

11,589,629

Sol

Chilean peso

124,877,836

128,304,143

Argentine peso

Chilean peso

8,443,710

12,822,660

TOTAL NON-CURRENT ASSETS

435,240,294

486,801,542

TOTAL ASSETS

476,970,314

539,605,280

F-136


						12-31-2012														12-31-2011
						Current Liabilities						Non-current Liabilities								Current Liabilities						Non-current Liabilities
						90 days or less		91 days to 1 year		Total Current		More than 1 year to 3 years		More than 3 years to 5 years		More than 5 years		Total Non-current		90 days or less		91 days to 1 year		Total Current		More than 1 year to 3 years		More than 3 years to 5 years		More than 5 years		Total Non-current
		Foreign Currency		Functional Currency		ThCh$		ThCh$		Total Current		ThCh$		ThCh$		ThCh$		Total Non-current		ThCh$		ThCh$		Total Current		ThCh$		ThCh$		ThCh$		Total Non-current
LIABILITIES
	Other current liabilities		U.S. dollar				104,128,409		255,065,083		359,193,492		487,384,775		223,960,388		450,043,533		1,161,388,696		50,273,399		110,007,608		160,281,007		698,191,147		484,059,182		493,795,421		1,676,045,750
			U.S. dollar		Chilean peso		24,749,455		234,307,578		259,057,033		424,225,534		157,063,940		411,509,374		992,798,848		23,913,216		58,161,835		82,075,051		595,227,849		359,668,296		436,744,073		1,391,640,218
			U.S. dollar		Brazilian real		486,256		7,606,194		8,092,450		16,493,010		9,064,986		3,838,731		29,396,727		644,936		12,599,186		13,244,122		17,532,685		17,877,446		6,352,599		41,762,730
			U.S. dollar		Peruvian sol		4,249,373		7,926,216		12,175,589		38,829,516		57,831,462		34,695,428		131,356,406		5,801,056		19,711,792		25,512,848		35,378,771		79,518,586		50,698,749		165,596,106
			U.S. dollar		Argentine peso		74,643,325		5,225,095		79,868,420		7,836,715		-		-		7,836,715		19,914,191		19,534,795		39,448,986		50,051,842		26,994,854		—		77,046,696

	TOTAL LIABILITIES						104,128,409		255,065,083		359,193,492		487,384,775		223,960,388		450,043,533		1,161,388,696		50,273,399		110,007,608		160,281,007		698,191,147		484,059,182		493,795,421		1,676,045,750

F-137

APPENDIX

6 ADDITIONAL INFORMATION OFICIO CIRCULAR (OFFICIAL BULLETIN) No. 715 OF FEBRUARY 3, 2012

This appendix forms an integral part of the Enersis financial statements.

a ) Portfolio stratification

Trade and other accounts receivable by time in arrears:


Trade and other accounts receivable	Balance at
	12-31-2012
	Up-to-date Portfolio ThCh$			1-30 days in arrears ThCh$			31-60 days in arrears ThCh$			61-90 days in arrears ThCh$			91-120 days in arrears ThCh$			121-150 days in arrears ThCh$			151-180 days in arrears ThCh$			181-210 days in arrears ThCh$			211-250 days in arrears ThCh$			More than 251 days in arrears ThCh$			Total Current ThCh$			Total Non-current ThCh$

Trade receivables, gross		577,631,678			85,836,682			31,117,064			14,481,479			7,021,733			6,325,361			5,023,586			3,995,097			4,173,859			166,502,746			902,109,285			163,265,685
Impairment provision		(2,348,483	)		(1,217,309	)		(396,729	)		(626,718	)		(2,690,963	)		(1,863,025	)		(1,995,194	)		(1,258,411	)		(916,663	)		(136,848,875	)		(150,162,370	)		-
Other accounts receivable, gross		130,237,560			-			-			-			-			-			-			-			-			-			130,237,560			39,712,008
Impairment provision		(12,979,909	)																										-			(12,979,909	)		-

Total		692,540,846			84,619,373			30,720,335			13,854,761			4,330,770			4,462,336			3,028,392			2,736,686			3,257,196			29,653,871			869,204,566			202,977,693


Trade and other accounts receivable	Balance at
	12-31-2011
	Up-to-date Portfolio ThCh$			1-30 days in arrears ThCh$			31-60 days in arrears ThCh$			61-90 days in arrears ThCh$			91-120 days in arrears ThCh$			121-150 days in arrears ThCh$			151-180 days in arrears ThCh$			181-210 days in arrears ThCh$			211-250 days in arrears ThCh$			More than 251 days in arrears ThCh$			Total Current ThCh$			Total Non-current ThCh$

Trade receivables, gross		534,607,770			79,940,683			35,672,835			12,874,596			8,896,804			7,584,496			5,471,489			8,895,281			4,139,605			366,906,201			1,064,989,760			182,387,693
Impairment provision		(2,786,319	)		(489,464	)		(185,027	)		(4,711,605	)		(3,233,750	)		(2,895,859	)		(4,921,080	)		(5,688,359	)		(1,381,095	)		(161,000,694	)		(187,293,252	)		(999,510	)
Other accounts receivable, gross		57,740,000			1,220,415			429,523			292,486			523,760			105,650			161,472			5,288,580			576,549			34,893,534			101,231,969			261,940,267
Impairment provision		(1,326,089	)		-			-			-			-			-			-			-			-			-			(1,326,089	)		-

Total		588,235,362			80,671,634			35,917,331			8,455,477			6,186,814			4,794,287			711,881			8,495,502			3,335,059			240,799,041			977,602,388			443,328,450

F-138

- By type of portfolio:


Time in Arrears	Balance at												Balance at
	12-31-2012												12-31-2011
	Non-renegotiated Portfolio				Renegotiated Portfolio				Total Gross Portfolio				Non-renegotiated Portfolio				Renegotiated Portfolio				Total Gross Portfolio
	Number of Clients		Gross Amount ThCh$		Number of Clients		Gross Amount ThCh$		Number of Clients		Gross Amount ThCh$		Number of Clients		Gross Amount ThCh$		Number of Clients		Gross Amount ThCh$		Number of Clients		Gross Amount ThCh$

Up to date		10,265,582		557,611,707		333,154		20,019,971		10,598,736		577,631,678		7,908,458		513,850,924		92,748		20,756,846		8,001,206		534,607,770
1 to 30 days		2,063,754		79,490,817		92,078		6,345,865		2,155,832		85,836,682		2,128,913		75,776,992		16,026		4,163,691		2,144,939		79,940,683
31 to 60 days		371,586		28,579,364		36,119		2,537,700		407,705		31,117,064		423,750		28,581,320		49,184		7,091,515		472,934		35,672,835
61 to 90 days		76,378		12,571,244		24,312		1,910,235		100,690		14,481,479		133,395		11,531,589		795		1,343,007		134,190		12,874,596
91 to 120 days		54,860		5,415,338		15,077		1,606,395		69,937		7,021,733		113,101		7,636,149		6,420		1,260,655		119,521		8,896,804
121 to 150 days		43,521		4,895,739		14,427		1,429,622		57,948		6,325,361		98,637		6,367,912		8,836		1,216,584		107,473		7,584,496
151 to 180 days		34,882		3,794,350		9,840		1,229,236		44,722		5,023,586		89,794		3,355,049		8,423		2,116,440		98,217		5,471,489
181 to 210 days		18,980		2,566,420		15,738		1,428,677		34,718		3,995,097		36,235		7,811,862		3,180		1,083,419		39,415		8,895,281
211 to 250 days		17,673		3,218,482		10,848		955,377		28,521		4,173,859		24,108		3,162,199		2,565		977,406		26,673		4,139,605
251 days and over		312,567		156,553,928		22,929		9,948,818		335,496		166,502,746		847,486		331,712,072		43,791		35,194,129		891,277		366,906,201

Total		13,259,783		854,697,389		574,522		47,411,896		13,834,305		902,109,285		11,803,877		989,786,068		231,968		75,203,692		12,035,845		1,064,989,760

b ) Portfolio in default and in legal collection process.

Portfolio in Default and in Legal Collection Process

Balance at

12-31-2012

12-31-2011

Number of
Clients

Amount

ThCh$

Number of
Clients

Amount

ThCh$

Notes receivable in default

154,337

19,650,395

50,995

17,482,266

Notes receivable in legal collection process (*)

11,333

24,548,940

11,033

26,318,280

Total

165,670

44,199,335

62,028

43,800,546

(*) Legal collections are included in the portfolio in arrears.

F-139

c ) Provisions and write-offs


Provisions and Write-offs	Balance at
	12-31-2012			12-31-2011
	ThCh$			ThCh$

Provision for non-renegotiated portfolio		25,406,355			21,443,190
Provision for renegotiated portfolio		1,683,468			527,254
Write-offs during the period		(16,073,728	)		(7,046,353	)
Recoveries during the period		6,083,566			(3,320,964	)

Total		17,099,661			11,603,127

d ) Number and amount of operations

Number and amount of operations

Balance at

12-31-2012

12-31-2011

Total detail by
type of
operation
Last Quarter

Total detail by
type of
operation
Annual
Accumulation

Total detail

by type of
operation
Last Quarter

Total detail by
type of
operation
Annual
Accumulation

ThCh$

Impairment provision and recoveries:

Number of operations

1,678,956

1,679,017

2,590,194

2,590,264

Amount of operations, in ThCh$

19,069,326

33,173,389

(1,048,188

)

18,649,480

F-140

APPENDIX 6.1 COMPLEMENTARY INFORMATION ON TRADE RECEIVABLES

This appendix forms an integral part of the Enersis financial statements.

a ) Portfolio stratification

- Trade receivables by time in arrears:


Trade Receivables	Balance at
	12-31-2012
	Up to date ThCh$			1-30 days in arrears ThCh$			31-60 days in arrears ThCh$			61-90 days in arrears ThCh$			91-120 days in arrears ThCh$			121-150 days in arrears ThCh$			151-180 days in arrears ThCh$			181-210 days in arrears ThCh$			211-250 days in arrears ThCh$			More than 250 days in arrears ThCh$			Total Current ThCh$			Total Non-current ThCh$

Generation and transmission receivables		162,178,765			814,505			47,700			4,335,174			308,432			274,643			28,484			-			311			66,123,434			234,111,448			140,323,852
-Large clients		115,182,971			201,283			635			6,290			82,886			272,789			2			-			311			18,340,888			134,088,055			-
-Institutional clients		18,748,525			-			-			-			-			-			-			-			-			-			18,748,525			140,323,852
-Others		28,247,269			613,222			47,065			4,328,884			225,546			1,854			28,482			-			-			47,782,546			81,274,868			-
Impairment provision		(260,312	)		-			-			-			-			-			-			-			-			(56,996,601	)		(57,256,913	)		-

Non-invoiced services		70,067,853			-			-			-			-			-			-			-			-			-			70,067,853			-
Invoiced services		92,110,912			814,505			47,700			4,335,174			308,432			274,643			28,484			-			311			66,123,434			164,043,595			140,323,852

Distribution receivables		415,452,913			85,022,177			31,069,364			10,146,305			6,713,301			6,050,718			4,995,102			3,995,097			4,173,548			100,379,312			667,997,837			22,941,833
-Mass-market clients		261,331,994			61,975,079			20,915,473			6,292,552			4,776,095			3,393,756			3,289,634			2,009,216			1,322,318			40,247,009			405,553,126			11,877,739
-Large clients		101,717,620			15,465,074			6,738,078			2,093,418			771,383			876,241			813,456			541,975			720,722			36,025,809			165,763,776			6,095,508
-Institutional clients		52,403,299			7,582,024			3,415,813			1,760,335			1,165,823			1,780,721			892,012			1,443,906			2,130,508			24,106,494			96,680,935			4,968,586
Impairment provision		(2,088,171	)		(1,217,309	)		(396,729	)		(626,718	)		(2,690,963	)		(1,863,025	)		(1,995,194	)		(1,258,411	)		(916,663	)		(79,852,274	)		(92,905,457	)		-

Non-invoiced services		207,144,462			-			-			-			-			-			-			-			-			1,239,251			208,383,713			-
Invoiced services		208,308,451			85,022,177			31,069,364			10,146,305			6,713,301			6,050,718			4,995,102			3,995,097			4,173,548			99,140,061			459,614,124			22,941,833

Total Trade Receivables, Gross		577,631,678			85,836,682			31,117,064			14,481,479			7,021,733			6,325,361			5,023,586			3,995,097			4,173,859			166,502,746			902,109,285			163,265,685
Total Impairment Provision		(2,348,483	)		(1,217,309	)		(396,729	)		(626,718	)		(2,690,963	)		(1,863,025	)		(1,995,194	)		(1,258,411	)		(916,663	)		(136,848,875	)		(150,162,370	)		-
Total Net Trade Receivables		575,283,195			84,619,373			30,720,335			13,854,761			4,330,770			4,462,336			3,028,392			2,736,686			3,257,196			29,653,871			751,946,915			163,265,685

Since not all of our commercial databases in our Group’s different subsidiaries distinguish whether the final electricity service consumer is a natural or legal person, the main management segmentation used by all the subsidiaries to monitor and follow up on trade receivables is the following:

Mass-market Clients

Large Clients

Institutional Clients

F-141


	Balance at
Trade Receivables	12-31-2011
Trade Receivables	Up to date ThCh$			1-30 days in arrears ThCh$			31-60 days in arrears ThCh$			61-90 days in arrears ThCh$			91-120 days in arrears ThCh$			121-150 days in arrears ThCh$			151-180 days in arrears ThCh$			181-210 days in arrears ThCh$			211-250 days in arrears ThCh$			More than 250 days in arrears ThCh$			Total Current ThCh$			Total Non-current ThCh$

Generation and Transmission Receivables		276,162,422			2,205,313			84,972			7,284,829			493,005			138,523			1,323,063			-			-			77,148,806			364,840,933			148,953,896
-Large clients		219,872,741			2,205,313			84,972			7,284,829			493,005			138,523			1,323,063			-			-			77,148,806			308,551,252			586,863
-Institutional clients		56,289,681			-			-			-			-			-			-			-			-			-			56,289,681			148,367,033
Impairment provision		(983,105	)		-			-			(4,110,640	)		(55,494	)		-			-			-			-			(43,766,186	)		(48,915,425	)		-

Non-invoiced services		108,875,974			-			-			-			-			-			-			-			-			-			108,875,974			-
Invoiced services		167,286,448			2,205,313			84,972			7,284,829			493,005			138,523			1,323,063			-			-			77,148,806			255,964,959			148,953,896

Distribution Receivables		258,445,348			77,735,369			35,587,863			5,589,767			8,403,798			7,445,973			4,148,425			8,895,281			4,139,606			289,757,397			700,148,827			33,433,797
-Mass-market clients		112,922,763			60,157,006			28,341,140			2,984,669			5,486,134			5,666,497			2,738,905			7,186,606			2,699,305			249,080,159			477,263,184			9,995,785
-Large clients		94,208,438			11,240,026			4,312,588			1,311,741			1,519,470			621,819			635,550			776,703			1,015,465			38,272,310			153,914,110			4,622,939
-Institutional clients		51,314,147			6,338,337			2,934,135			1,293,357			1,398,194			1,157,657			773,970			931,972			424,836			2,404,928			68,971,533			18,815,073
Impairment provision		(1,803,214	)		(489,464	)		(185,027	)		(600,965	)		(3,178,256	)		(2,895,859	)		(4,921,080	)		(5,688,359	)		(1,381,095	)		(117,234,508	)		(138,377,827	)		(999,510	)

Non-invoiced services		150,400,140			-			-			-			-			-			-			-			-			-			150,400,140			-
Invoiced services		108,045,208			77,735,370			35,587,863			5,589,767			8,403,799			7,445,973			4,148,426			8,895,281			4,139,605			289,757,395			549,748,687			33,433,797

Total Trade Receivables, Gross		534,607,770			79,940,682			35,672,835			12,874,596			8,896,803			7,584,496			5,471,488			8,895,281			4,139,606			366,906,203			1,064,989,760			182,387,693
Total Impairment Provision		(2,786,319	)		(489,464	)		(185,027	)		(4,711,605	)		(3,233,750	)		(2,895,859	)		(4,921,080	)		(5,688,359	)		(1,381,095	)		(161,000,694	)		(187,293,252	)		(999,510	)
Total Net Trade Receivables		531,821,451			79,451,218			35,487,808			8,162,991			5,663,053			4,688,637			550,408			3,206,922			2,758,511			205,905,509			877,696,508			181,388,183

F-142

- By type of portfolio:


Type of Portfolio		Balance at
		12-31-2012
	Up to date ThCh$		1-30 days in arrears ThCh$		31-60 days in arrears ThCh$		61-90 days in arrears ThCh$		91-120 days in arrears ThCh$		121-150 days in arrears ThCh$		151-180 days in arrears ThCh$		181-210 days in arrears ThCh$		211-250 days in arrears ThCh$		More than 250 days in arrears ThCh$		Total portfolio, gross ThCh$
GENERATION AND TRANSMISSION
Non-renegotiated portfolio		155,229,004		814,505		47,700		4,311,860		308,432		274,643		4,577		-		311		65,515,189		226,506,221
-Large clients		115,182,971		201,283		635		6,290		82,886		272,789		2		-		311		18,340,888		134,088,055
-Institutional clients		18,748,525		-		-		-		-		-		-		-		-		-		18,748,525
-Others		21,297,508		613,222		47,065		4,305,570		225,546		1,854		4,575		-		-		47,174,301		73,669,641
Renegotiated portfolio		6,949,761		-		-		23,314		-		-		23,907		-		-		608,245		7,605,227
-Large clients		-		-		-		-		-		-		-		-		-		-		-
-Institutional clients		-		-		-		-		-		-		-		-		-		-		-
-Others		6,949,761		-		-		23,314		-		-		23,907		-		-		608,245		7,605,227
DISTRIBUTION
Non-renegotiated portfolio		402,382,703		78,676,312		28,531,664		8,259,384		5,106,906		4,621,096		3,789,773		2,566,420		3,218,171		91,038,739		628,191,168
-Mass-market clients		252,003,889		57,670,992		19,067,440		5,008,539		3,688,532		2,463,672		2,491,643		1,318,921		731,935		32,414,708		376,860,271
-Large clients		100,406,979		14,047,180		6,585,752		1,954,431		692,787		843,697		772,966		497,816		687,530		35,801,753		162,290,891
-Institutional clients		49,971,835		6,958,140		2,878,472		1,296,414		725,587		1,313,727		525,164		749,683		1,798,706		22,822,278		89,040,006
Renegotiated portfolio		13,070,210		6,345,865		2,537,700		1,886,921		1,606,395		1,429,622		1,205,329		1,428,677		955,377		9,340,573		39,806,669
-Mass-market clients		8,681,754		3,795,249		1,846,968		1,283,578		1,094,281		929,814		797,592		689,649		590,346		7,807,681		27,516,912
-Large clients		1,194,312		791,220		140,433		139,948		78,339		32,945		41,019		44,993		33,298		253,891		2,750,398
-Institutional clients		3,194,144		1,759,396		550,299		463,395		433,775		466,863		366,718		694,035		331,733		1,279,001		9,539,359

Total Portfolio, Gross		577,631,678		85,836,682		31,117,064		14,481,479		7,021,733		6,325,361		5,023,586		3,995,097		4,173,859		166,502,746		902,109,285

F-143


Types of Portfolio	Balance at
	12-31-2011
	Up to date ThCh$		1-30 days in arrears ThCh$		31-60 days in arrears ThCh$		61-90 days in arrears ThCh$		91-120 days in arrears ThCh$		121-150 days in arrears ThCh$		151-180 days in arrears ThCh$		181-210 days in arrears ThCh$		211-250 days in arrears ThCh$		More than 250 days in arrears ThCh$		Total portfolio, gross ThCh$
GENERATION AND TRANSMISSION
Non-renegotiated portfolio		256,097,955		2,205,313		2,894,669		4,727,650		493,005		-		935,644		-		-		72,143,556		339,497,792
-Large clients		206,702,908		2,205,313		2,894,669		4,727,650		493,005		-		935,644		-		-		72,143,556		290,102,745
-Institutional clients		49,395,047		-		-		-		-		-		-		-		-		-		49,395,047
Renegotiated portfolio		-		-		-		-		-		-		-		-		-		-		-
-Large clients		-		-		-		-		-		-		-		-		-		-		-
-Institutional clients		-		-		-		-		-		-		-		-		-		-		-
DISTRIBUTION
Non-renegotiated portfolio		257,752,969		73,571,679		25,686,651		6,803,939		7,143,144		6,367,912		2,419,405		7,811,862		3,162,199		259,568,517		650,288,277
-Mass-market clients		116,163,607		56,976,736		19,972,918		4,801,938		5,568,695		5,865,662		1,812,061		7,121,529		2,250,787		224,276,812		444,810,745
-Large clients		93,126,921		11,031,598		3,980,710		1,152,224		1,453,185		490,552		554,707		690,333		911,412		35,291,705		148,683,347
-Institutional clients		48,462,441		5,563,345		1,733,023		849,777		121,264		11,698		52,637		-		-		-		56,794,185
Renegotiated portfolio		20,756,846		4,163,691		7,091,516		1,343,007		1,260,655		1,216,584		2,116,440		1,083,419		977,406		35,194,127		75,203,691
-Mass-market clients		16,403,309		3,111,313		5,410,638		690,352		622,125		532,578		857,606		349,526		267,212		10,304,763		38,549,422
-Large clients		1,131,708		224,970		341,266		167,209		72,709		139,446		86,961		90,179		108,624		3,024,804		5,387,876
-Institutional clients		3,221,829		827,408		1,339,612		485,446		565,821		544,560		1,171,873		643,714		601,570		21,864,560		31,266,393

Total Portfolio, Gross		534,607,770		79,940,683		35,672,836		12,874,596		8,896,804		7,584,496		5,471,489		8,895,281		4,139,605		366,906,200		1,064,989,760

F-144

SCHEDULE I

Rule 5-04 of the Securities and Exchange Commission requires presentation of condensed financial statements of the registrant (parent company) when restricted net asset, defined as assets not to be transferred to the parent company in the form of loans, advance or cash dividends of the subsidiary without the consent of a third party, exceed of the 25% consolidated net assets of the parent and its subsidiaries.

Following are the Enersis separate statements of financial position as of December 31, 2012 and 2011 and the related statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2012, have been prepared in accordance with International Financial Reporting Standards.

ENERSIS S.A.

Separate Statement of Financial Position

At December 31, 2012 and 2011

(In thousands of Chilean pesos - ThCh$)


ASSETS	12-31-2012		12-31-2011
ASSETS	ThCh$		ThCh$

CURRENT ASSETS
Cash and cash equivalents		203,350,075		328,709,300
Other current non-financial assets		591,537		432,477
Trade and other current receivables		3,398,177		5,307,457
Accounts receivable from related companies		197,239,223		45,295,153
Inventories		4,315,433		5,651,622
Current tax assets		20,555,750		10,746,284
Total current assets other than assets classified as held for sale and discontinued operations		429,450,195		396,142,293

Non-current assets classified as held for sale and discontinued operations				-

TOTAL CURRENT ASSETS		429,450,195		396,142,293

NON-CURRENT ASSETS
Other non-current financial assets		27,045,746		20,793,960
Non-current receivables				-
Investments in subsidiaries, at cost		2,407,743,084		2,407,743,084
Intangible assets other than goodwill		2,259,343		1,848,204
Property, plant and equipment, net		5,985,062		6,831,258
Deferred tax assets		49,529,306		39,818,448

TOTAL NON-CURRENT ASSETS		2,492,562,541		2,477,034,954

TOTAL ASSETS		2,922,012,736		2,873,177,247

F-145

ENERSIS S.A.

Separate Statement of Financial Position

At December 31, 2012 and 2011

(In thousands of Chilean pesos - ThCh$)


LIABILITIES AND EQUITY	12-31-2012			12-31-2011
	ThCh$			ThCh$

CURRENT LIABILITIES
Other current financial liabilities		12,771,891			12,336,371
Trade and other current payables		57,210,948			49,990,132
Accounts payable to related companies		70,185,939			79,076,032
Other current provisions		5,576,621			13,485,579
Current tax liabilities		1,028,454			302,633
Current provisions for employee benefits
Other current non-financial liabilities		494,441			341,616
Total current liabilities other than those associated with current assets classified as held for sale and discontinued operations		147,268,294			155,532,363

Liabilities associated with current assets classified as held for sale and discontinued operations					-

TOTAL CURRENT LIABILITIES		147,268,294			155,532,363

NON-CURRENT LIABILITIES
Other non-current financial liabilities		551,669,663			553,642,026
Deferred tax liabilities		1,601,425			1,833,765
Non-current provisions for employee benefits		5,877,316			5,359,699

TOTAL NON-CURRENT LIABILITIES		559,148,404			560,835,490

TOTAL LIABILITIES		706,416,698			716,367,853

EQUITY
Issued capital		2,824,882,835			2,824,882,835
Retained earnings		534,511,449			486,707,243
Share premium		158,759,648			158,759,648
Other reserves		(1,302,557,894	)		(1,313,540,332	)

TOTAL EQUITY		2,215,596,038			2,156,809,394

TOTAL LIABILITIES AND EQUITY		2,922,012,736			2,873,177,247

F-146

ENERSIS S.A.

Separate Statement of Comprehensive Income

For the years ended December 31, 2012, 2011 and 2010

(In thousands of Chilean pesos - ThCh$)


STATEMENT OF COMPREHENSIVE INCOME		2012			2011			2010
STATEMENT OF COMPREHENSIVE INCOME	ThCh$			ThCh$			ThCh$
Dividends from a subsidiaries and other revenues(*)		290,475,777			400,034,628			249,037,939
Other operating income		14,867,439			14,504,696			15,184,438
Total Revenues		305,343,216			414,539,324			264,222,377

Raw materials and consumable used		(15,745,496	)		(14,798,705	)		(3,802,716	)
Contribution Margin		289,597,720			399,740,619			260,419,661
Employee benefits expense		(19,546,232	)		(16,713,154	)		(16,829,950	)
Depreciation and amortization expense		(1,019,576	)		(1,050,299	)		(933,976	)
Impairment loss recognized in the year’s profit or loss		-			(149,027,067	)		-
Other miscellaneous operating expenses		(13,861,870	)		(12,833,294	)		(13,734,299	)
Operating Income		255,170,042			220,116,805			228,921,436

Profit (Loss) on derecognition of available-for-sale financial assets		(5,850	)		22,793,523			-
Financial cost		(19,504,727	)		(29,348,484	)		(30,590,442	)
Foreign currency exchange differences		(5,722,112	)		6,580,169			(13,591,211	)
Profit (loss) for indexed assets and liabilities		(12,954,832	)		(19,881,258	)		(12,195,357	)
Net Income Before Tax		216,982,521			200,260,755			172,544,426
Income Tax		19,690,401			470,914			6,031,074
Net Income from Continuing Operations		236,672,922			200,731,669			178,575,500
Net Income from discontinued operations								-
NET INCOME		236,672,922			200,731,669			178,575,500

Components of other comprehensive income, before taxes
Gains (losses) on cash flow hedge		13,036,981			15,532,787			1,695,814
Actuarial gain (loss) on defined benefit plans		(772,170	)		(127,086	)		73,634
Total components of other comprehensive income, before taxes		12,264,811			15,405,701			1,769,448

Income tax related to components of other comprehensive income
Income tax related to cash flow hedge		(2,054,542	)		(2,640,574	)		(288,289	)
Income tax related to defined benefit plans		201,645			21,605			(12,518	)
Total income tax		(1,852,897	)		(2,618,969	)		(300.807	)

Total Other Comprehensive Income		10,411,914			12,786,732			1,468,641
TOTAL COMPREHENSIVE INCOME		247,084,836			213,518,401			180,044,141

(*)	Includes revenues from sales of electrical materials for ThCh$ 19,235,365 in 2012, ThCh$ 18,913,641 in 2011 and ThCh$ 4,790,239 in 2010.

F-147

ENERSIS S.A.

Separate Statement of Changes in Equity

For the years ended December 31, 2012, 2011 and 2010

(In thousands of Chilean pesos - ThCh$)


Statement of Changes in Equity, Net					Changes in other reserves
Statement of Changes in Equity, Net	Issued capital		Share Premium		Reserve of cash flow hedge		Reserve of actuarial gains or losses on defined benefit plans		Other miscellaneous reserves		Other reserves		Retained earnings		Total Equity
Equity at beginning of period 01/01/2012		2,824,882,835		158,759,648		(15,427,433)		-		(1,298,112,899)		(1,313,540,332)		486,707,243		2,156,809,394
Changes in equity
Comprehensive income						10,982,439		(570,525)				10,411,914		236,672,922		247,084,836
Net income														236,672,922		236,672,922
Other comprehensive income						10,982,439		(570,525)				10,411,914				10,411,914
Comprehensive Income
Dividends														(188,298,192)		(188,298,192)
Increase (decrease) through transfers and other changes						131,799		570,525		(131,799)		570,525		(570,525)
Total changes in equity						11,114,238				(131,799)		10,982,439		47,804,205		58,786,644
Equity at end of year 12/31/2012		2,824,882,835		158,759,648		(4,313,195)		-		(1,298,244,698)		(1,302,557,893)		534,511,448		2,215,596,038


Statement of Changes in Equity, Net					Changes in other reserves
Statement of Changes in Equity, Net	Issued capital		Share Premium		Reserve of cash flow hedge		Reserve of actuarial gains or losses on defined benefit plans		Other miscellaneous reserves		Other reserves		Retained earnings		Total Equity
Equity at beginning of period 01/01/2011		2,824,882,835		158,759,648		(28,319,646)		-		(1,298,112,899)		(1,326,432,545)		495,967,789		2,153,177,727
Changes in equity
Comprehensive income						12,892,213		(105,481)				12,786,732		200,731,669		213,518,401
Net income						-								200,731,669		200,731,669
Other comprehensive income						12,892,213		(105,481)				12,786,732				12,786,732
Comprehensive Income
Dividends														(209,886,734)		(209,886,734)
Increase (decrease) through transfers and other changes								105,481				105,481		(105,481)		-
Total changes in equity						12,892,213		-				12,892,213		(9,260,546)		3,631,667
Equity at end of year 12/31/2011		2,824,882,835		158,759,648		(15,427,433)		-		(1,298,112,899)		(1,313,540,332)		486,707,243		2,156,809,394

F-148

ENERSIS S.A.

Separate Statement of Changes in Equity

For the years ended December 31, 2012, 2011 and 2010

(In thousands of Chilean pesos - ThCh$)


Statement of Changes in Equity, Net					Changes in other reserves
Statement of Changes in Equity, Net	Issued capital		Share Premium		Reserve of cash flow hedge		Reserve of actuarial gains or losses on defined benefit plans		Other miscellaneous reserves		Other reserves		Retained earnings		Total Equity
Equity at beginning of period 01/01/2010		2,824,882,835		158,759,648		(29,727,171)		-		(1,298,112,899)		(1,327,840,070)		496,953,186		2,152,755,599
Changes in equity
Comprehensive income						1,407,525		61,116				1,468,641		178,575,500		180,044,141
Net income														178,575,500		178,575,500
Other comprehensive income						1,407,525		61,116				1,468,641				1,468,641
Comprehensive Income
Dividends														(179,622,013)		(179,622,013)
Increase (decrease) through transfers and other changes								(61,116)				(61,116)		61,116		-
Total changes in equity						1,407,525						1,407,525		(985,397)		422,128
Equity at end of year 12/31/2010		2,824,882,835		158,759,648		(28,319,646)		-		(1,298,112,899)		(1,326,432,545)		495,967,789		2,153,177,727

F-149

ENERSIS S.A.

Separate Statement of Cash Flows

For the years ended December 31, 2012, 2011 and 2010

(In thousands of Chilean pesos - ThCh$)


	2012			2011			2010
Statement of Direct Cash Flow	ThCh$			ThCh$			ThCh$
Cash flows from (used in) operating activities
Types of collections from operating activities
Collections from the sale of goods and services		15,480,170			24,558,500			11,980,151
Collections from royalties, payments, commissions, and other income from ordinary activities		20,845,453			11,677,458			13,710,820
Other collections from operating activities		575,444			153,937			-
Types of payments
Payments to suppliers for goods and services		(19,805,947	)		(20,151,765	)		(11,957,836	)
Payments to and on behalf of employees		(16,660,790	)		(15,353,879	)		(13,090,048	)
Other payments for operating activities		(8,861,433	)		(21,265,185	)		(5,616,563	)
Income tax reimbursed (paid)		(2,931,311	)		636,356			419,096
Other inflows (outflows) of cash		(7,033,011	)		(10,749,578	)		(45,322,204	)
Net cash flows from (used in) operating activities		(18,391,425	)		(30,494,156	)		(49,876,584	)

Cash flows from (used in) investing activities
Proceeds from the sale of Other Financial Assets					31,486,668			-
Other cash flows provided by (used in) investing activities		209,417,363			161,163,996			17,031,549
Proceeds from dividends received classified for investing purposes		287,779,731			374,143,660			211,194,885
Purchase of property, plant and equipment		(1,266,889	)		(700,846	)		(236,768	)
Investments in subsidiaries		-			-			-
Loans to related companies		(375,042,775	)		(2,067,881	)		(821,636	)
Interest received		18,136,817			9,826,441			7,533,195
Other investment disbursements		(7,849,414	)		-			(6,356,992	)
Net cash flows from (used in) investing activities		131,174,833			573,852,038			228,344,233

Cash flows from (used in) financing activities
Proceeds from loans obtained		608,503			-			-
Proceeds from loans from related companies		108,382,598			-			5,536,031
Repayments of borrowings		(2,381,601	)		(1,943,349	)		(1,585,498	)
Payments of finance lease liabilities		-			-			-
Payments from loans to related companies		(118,364,087	)		(7,072,402	)		-
Dividend paid to shareholders		(186,207,746	)		(242,669,579	)		(120,644,562	)
Interest paid		(25,089,047	)		(25,659,530	)		(26,402,662	)
Other inflows (outflows) of cash		(12,217,090	)		-			-
Net cash flows from (used in) financing activities		(235,268,470	)		(277,344,860	)		(143,096,691	)

Net increase (decrease) in cash and cash equivalents before effect of exchange rate changes		(122,485,062	)		266,013,022			35,370,958

Effect of exchange rate changes on cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents		(2,874,163	)
Net increase (decrease) in cash and cash equivalents		(125,359,225	)		266,013,022			35,370,958
Cash and cash equivalents at beginning of year		328,709,300			62,696,278			27,325,320
Cash and cash equivalents at end of year		203,350,075			328,709,300			62,696,278

F-150

Additional information:

1. Basis of Presentation

Enersis S.A. (“the Parent”) is a holding company that conducts substantially all of its business operations through its subsidiaries. It is important to consider that for purposes of preparing separate financial statements under International Financial Reporting Standards, the Parent records its investments in subsidiaries and associates at its cost. Dividends received from a subsidiary and associate are recognized in profit or loss in the Parent’s separate financial statements when its right to receive such dividend is established. The information described bellow should be read in conjunction with the consolidated financial statements of Enersis S.A. The basis of presentation and accounting principles used in the preparation of these separate financial statements are described in notes 2 and 3 of the consolidated financial statements except for notes 2.4, 2.4.1, 2.4.2, 2.4.3, 2.5, 2.6 and 3.c which relates to the consolidation process.

2. Restricted Net Assets

Certain assets of the Parent’s subsidiaries totaling approximately ThCh$ 1,462,021,652 constitute restricted net assets, as there are contractual, legal or regulatory limitations on transferring such assets outside of the countries where the respective assets are located, or because they constitute undistributed earnings of affiliates of the Parent recorded under the equity method of accounting. As of December 31, 2012 all of the restricted net assets of the Parent’s subsidiaries currently exceed 25% of the consolidated net assets of the Parent and its subsidiaries, thus requiring this Schedule I, “Condensed Financial Information of the Registrant.”

3. Refer to the following notes in the consolidated financial statements of Enersis for the year ended December 31, 2012:

Note 18 for long-term debt

Note 24 for dividends paid

Note 34 for contingencies and guaranties

F-151